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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549


FORM 10-Q

x
    
    Quarterly report pursuant to section 13 or 15(d) of the Securities Exchange
Act of 1934o
    
    Transition report pursuant to section 13 or 15(d) of the Securities
Exchange Act of 1934


For the Quarter Ended: September 30, 2003
    
    Commission File No. 333-42638


NRG Northeast Generating LLC

(Exact name of Registrant as specified in its charter)


Delaware
    
    41-1937472(State or other jurisdiction
of incorporation or organization)
    
    (I.R.S. Employer
Identification No.)901 Marquette Avenue, Suite 2300
Minneapolis, Minnesota
    
    55402(Address of principal executive offices)
    
    (Zip Code)


(612) 373-5300

(Registrants telephone number, including area code)


None(Former name, former address and former fiscal year, if changed since
last report)

Indicate by check mark whether the Registrant (1) has filed all reports to
be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the Registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.

Yes x     No o

Indicate by check mark whether the Registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act)

Yes o     No x

Indicate by check mark whether the registrant has filed all documents and
reports required to be filed by Section 12, 13 or 15(d) of the Securities and
Exchange Act of 1934 subsequent to the distribution of securities under a plan
confirmed by a court.

Yes x     No o



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TABLE OF CONTENTS



|                                  |                                                                                               |                                            |  |  |  |  |  | 
|--------------------------------- | --------------------------------------------------------------------------------------------- | ------------------------------------------ |  |  |  |  |  | 
|Part I  FINANCIAL INFORMATION   
|                                  | Item I  Consolidated Financial Statements and Notes                                         
|                                  |                                                                                               | Consolidated Statements of Operations     
|                                  |                                                                                               | Consolidated Balance Sheets               
|                                  |                                                                                               | Consolidated Statements of Members Equity
|                                  |                                                                                               | Consolidated Statements of Cash Flows     
|                                  |                                                                                               | Notes to Consolidated Financial Statements
|                                  | Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
|                                  | Item 3. Quantitative and Qualitative Disclosures About Market Risk                           
|                                  | Item 4. Controls and Procedures                                                              
|Part II  OTHER INFORMATION      
|                                  | Item 1. Legal Proceedings                                                                    
|                                  | Item 3. Defaults Upon Senior Securities                                                      
|                                  | Item 6. Exhibits, Financial Statement Schedules, and Reports on Form 8-K                     
|                                  | Cautionary Statement Regarding Forward-Looking Statements                                    
|SIGNATURES                       
|EX-31.1 Section 302 Certification
|EX-31.2 Section 302 Certification
|EX-31.3 Section 302 Certification
|EX-32 Section 906 Certification  



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TABLE OF CONTENTS

INDEX

Page No.Part IItem 1 Consolidated Financial Statements and NotesConsolidated Statements of Operations

    
    3Consolidated Balance Sheets
    
    
    4Consolidated Statements of Members Equity
    
    
    5Consolidated Statements of Cash Flows
    
    
    6Notes to Consolidated Financial Statements
    
    
    7Item 2 Managements Discussion and Analysis of Financial Condition and Results of Operations
    
    
    31Item 3 Quantitative and Qualitative Disclosures About Market Risk
    
    
    31Item 4 Controls and Procedures
    
    
    31Part IIItem 1 Legal Proceedings
    
    
    32Item 3 Defaults on Senior Securities
    
    
    32Item 6 Exhibits, Financial Statement Schedules, and Reports on Form 8-K
    
    
    32Cautionary Statement Regarding Forward Looking Information
    
    
    32SIGNATURES
    
    
    35


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Part I  FINANCIAL INFORMATION

Item I  Consolidated Financial Statements and Notes

NRG Northeast Generating LLC and Subsidiaries
Consolidated Statements of Operations
(UNAUDITED)

Three Months Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,(In thousands)
    
    2003
    

2002(Restated)
    
    2003
    
    2002(Restated)Operating revenuesRevenues
    
    $
    260,472
    
    
    $
    233,604
    
    
    $
    603,858
    
    
    $
    550,252Operating costs and expensesOperating costs
    
    
    145,400
    
    
    
    182,104
    
    
    
    500,601
    
    
    
    390,657Depreciation
    
    
    14,295
    
    
    
    13,639
    
    
    
    51,065
    
    
    
    39,790General and administrative expenses
    
    
    12,568
    
    
    
    5,330
    
    
    
    29,915
    
    
    
    16,671Restructuring professional fees and
expenses
    
    
    515
    
    
    
    
    
    
    
    1,081
    
    
    
    Restructuring and impairment charges
    
    
    9,088
    
    
    
    49,289
    
    
    
    232,335
    
    
    
    49,289Operating (loss) income
    
    
    78,606
    
    
    
    (16,758
    )
    
    
    (211,139
    )
    
    
    53,845Other income (expense)Other income, net
    
    
    (27
    )
    
    
    133
    
    
    
    (23
    )
    
    
    5,167Restructuring interest income
    
    
    2
    
    
    
    
    
    
    
    5
    
    
    
    Interest expense
    
    
    (14,600
    )
    
    
    (12,877
    )
    
    
    (40,302
    )
    
    
    (39,621
    )Net (loss) income
    
    $
    63,981
    
    
    $
    (29,502
    )
    
    $
    (251,459
    )
    
    $
    19,391


See accompanying notes to consolidated financial statements.

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NRG Northeast Generating LLC and Subsidiaries
Consolidated Balance Sheets (UNAUDITED)

September 30,
    
    December 31,(In thousands)
    
    2003
    
    2002AssetsCurrent Assets:Cash and cash equivalents
    
    $
    126
    
    
    $
    14,354Cash  restricted
    
    
    3,555
    
    
    
    Accounts receivable, net of allowance for doubtful accounts of $0 and $1,344
    
    
    285
    
    
    
    118,153Accounts receivable  affiliate
    
    
    622,893
    
    
    
    Inventory
    
    
    130,175
    
    
    
    123,963Derivative instruments valuation
    
    
    253
    
    
    
    23,039Prepaid expenses
    
    
    39,489
    
    
    
    38,309Total current assets
    
    
    796,776
    
    
    
    317,818Property, plant and equipment, net of accumulated depreciation of $163,139 and $157,534
    
    
    1,056,068
    
    
    
    1,333,928Deferred finance costs, net of accumulated amortization of $4,281 and $1,161
    
    
    13,412
    
    
    
    8,995Derivative instruments valuation
    
    
    
    
    
    
    9,601Other assets, net of accumulated amortization of $4,359 and $2,605
    
    
    28,996
    
    
    
    23,395Total assets
    
    $
    1,895,252
    
    
    $
    1,693,737Liabilities and Members EquityLiabilities:Current portion of long-term debt
    
    $
    
    
    
    $
    556,500Note payable  affiliate
    
    
    
    
    
    
    30,000Accounts payable
    
    
    
    
    
    
    14,607Accounts
payable  affiliates
    
    
    
    
    
    
    11,476Accrued fuel and purchased power expense
    
    
    
    
    
    
    37,168Accrued interest
    
    
    14,993
    
    
    
    4,198Other accrued liabilities
    
    
    6,341
    
    
    
    11,713Derivative instruments valuation
    
    
    646
    
    
    
    13,017Total current liabilities
    
    
    21,980
    
    
    
    678,679Derivative instruments valuation
    
    
    
    
    
    
    7,559Other long-term obligations
    
    
    348
    
    
    
    27,936Total liabilities not subject to compromise
    
    
    22,328
    
    
    
    714,174Liabilities subject to compromise:Notes payable
    
    
    586,500
    
    
    
    Accounts payable  trade
    
    
    20
    
    
    
    Accounts payable  affiliate
    
    
    522,278
    
    
    
    Accrued liabilities
    
    
    46,586
    
    
    
    Other liabilities
    
    
    18,271
    
    
    
    Total liabilities subject to compromise
    
    
    1,173,655
    
    
    
    Commitments and contingenciesMembers equity
    
    
    699,269
    
    
    
    979,563Total liabilities and members equity
    
    $
    1,895,252
    
    
    $
    1,693,737


See accompanying notes to consolidated financial statements.

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NRG Northeast Generating LLC and Subsidiaries
Consolidated Statements of Members Equity (UNAUDITED)

For the three months ended September 30, 2003 and 2002

AccumulatedMember
    
    
    
    
    
    Other
    
    TotalContributions/
    
    Accumulated
    
    Comprehensive
    
    Members '(In thousands)
    
    Distributions
    
    Net Income (Loss)
    
    Income (Loss)
    
    EquityBalances at June 30, 2002
    
    $
    788,315
    
    
    $
    207,421
    
    
    $
    66,772
    
    
    $
    1,062,508Net loss
    
    
    
    
    
    
    (29,502
    )
    
    
    
    
    
    
    (29,502
    )Deferred unrealized gains on derivatives, net
    
    
    
    
    
    
    
    
    
    
    19,035
    
    
    
    19,035Comprehensive loss
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (10,467
    )Balances
at September 30, 2002, as restated
    
    $
    788,315
    
    
    $
    177,919
    
    
    $
    85,807
    
    
    $
    1,052,041Balances at June 30, 2003
    
    $
    788,315
    
    
    $
    (153,027
    )
    
    $
    
    
    
    $
    635,288Net income
    
    
    
    
    
    
    63,981
    
    
    
    
    
    
    
    63,981Comprehensive income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    63,981Balances at September 30, 2003
    
    $
    788,315
    
    
    $
    (89,046
    )
    
    $
    
    
    
    $
    699,269


For the nine months ended September 30, 2003 and 2002

Member
    
    
    
    
    
    Accumulated Other
    
    TotalContributions/
    
    Accumulated
    
    Comprehensive
    
    Members '(In thousands)
    
    Distributions
    
    Net Income (Loss)
    
    Income (Loss)
    
    EquityBalances at December 31, 2001
    
    $
    788,315
    
    
    $
    158,528
    
    
    $
    107,741
    
    
    $
    1,054,584Net income
    
    
    
    
    
    
    19,391
    
    
    
    
    
    
    
    19,391Deferred unrealized loss on derivatives, net
    
    
    
    
    
    
    
    
    
    
    (21,934
    )
    
    
    (21,934
    )Comprehensive
loss
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (2,543
    )Balances
at September 30, 2002, as restated
    
    $
    788,315
    
    
    $
    177,919
    
    
    $
    85,807
    
    
    $
    1,052,041Balances at December 31, 2002
    
    $
    788,315
    
    
    $
    162,413
    
    
    $
    28,835
    
    
    $
    979,563Net loss
    
    
    
    
    
    
    (251,459
    )
    
    
    
    
    
    
    (251,459
    )Deferred unrealized loss on derivatives, net
    
    
    
    
    
    
    
    
    
    
    (28,835
    )
    
    
    (28,835
    )Comprehensive loss
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (280,294
    )Balances at September 30, 2003
    
    $
    788,315
    
    
    $
    (89,046
    )
    
    $
    
    
    
    $
    699,269


See accompanying notes to consolidated financial statements.

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NRG Northeast Generating LLC and Subsidiaries
Consolidated Statements of Cash Flows (UNAUDITED)

Nine MonthsNine Months
    
    EndedEnded
    
    September
30, 2002(In thousands)
    
    September 30, 2003
    
    (Restated)Cash flows from operating activities:Net (loss)/income
    
    $
    (251,459
    )
    
    $
    19,391Adjustments to reconcile net (loss)/income to net cash provided (used) by operating activitiesDepreciation
    
    
    51,883
    
    
    
    37,990Unrealized
(gain)loss on energy contracts
    
    
    (16,377
    )
    
    
    8,614Amortization of other assets
    
    
    
    
    
    
    651Amortization of deferred financing costs
    
    
    3,120
    
    
    
    310Asset and impairments
    
    
    230,570
    
    
    
    49,289Allowance for doubtful accounts
    
    
    1,344
    
    
    
    (Gain) loss on disposal of property and equipment
    
    
    (818
    )
    
    
    1,800Changes in assets and liabilities:Accounts receivable, net
    
    
    116,524
    
    
    
    (43,388
    )Inventory
    
    
    (6,212
    )
    
    
    57,418Prepaid expenses
    
    
    (1,180
    )
    
    
    (15,099
    )Accounts payable
    
    
    (14,587
    )
    
    
    (1,410
    )Accounts receivable/payable  affiliates, net
    
    
    (112,091
    )
    
    
    (70,752
    )Accrued interest
    
    
    12,993
    
    
    
    14,382Accrued fuel and purchased power expense
    
    
    (3,841
    )
    
    
    (19,881
    )Other accrued liabilities
    
    
    23,960
    
    
    
    7,939Other assets and liabilities
    
    
    (33,383
    )
    
    
    (1,708
    )Net cash provided by operating activities
    
    
    446
    
    
    
    45,546Cash flows from investing activities:Capital expenditures
    
    
    (8,458
    )
    
    
    (21,788
    )Investment in restricted funds
    
    
    (3,555
    )
    
    
    (310
    )Proceeds from disposition of property and equipment
    
    
    4,876
    
    
    
    Net cash used by investing activities
    
    
    (7,137
    )
    
    
    (22,098
    )Cash flows from financing activities:Deferred financing costs
    
    
    (7,537
    )
    
    
    Proceeds from note payable  affiliate
    
    
    
    
    
    
    30,000Principal payments on long-term debt
    
    
    
    
    
    
    (53,500
    )Net cash used by financing activities
    
    
    (7,537
    )
    
    
    (23,500
    )Net decrease in cash and cash equivalents
    
    
    (14,228
    )
    
    
    (52
    )Cash and cash equivalents at beginning of period
    
    
    14,354
    
    
    
    370Cash and cash equivalents at end of period
    
    $
    126
    
    
    $
    318


See accompanying notes to consolidated financial statements.

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NRG Northeast Generating LLC and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

NRG Northeast Generating LLC (the Company or NRG Northeast), a
wholly-owned indirect subsidiary of NRG Energy, Inc. (NRG Energy), owns
electric power generation plants in the northeastern region of the United
States. The Company was formed for the purpose of financing, acquiring, owning,
operating and maintaining, through its subsidiaries and affiliates; facilities
owned by Arthur Kill Power LLC, Astoria Gas Turbine Power LLC, Connecticut Jet
Power LLC, Devon Power LLC, Dunkirk Power LLC, Huntley Power LLC, Middletown
Power LLC, Montville Power LLC, Norwalk Power LLC, Oswego Power LLC and
Somerset Power LLC.

On May 14, 2003 (The Petition Date) NRG Energy and 26 of its affiliates
(the Debtors) (including the Company and its subsidiaries) filed voluntary
petitions for reorganization under Chapter 11 of the United States Bankruptcy
Code (the Bankruptcy Code) in the United States Bankruptcy Court for the
Southern District of New York (the Bankruptcy Court) in re: NRG ENERGY, INC.,
et al., Case No. 03-13024 (PCB) (such proceedings, the Chapter 11 Cases).
See Note 2 for a complete list of debtors.
It is possible that additional
subsidiaries will file petitions for reorganization under Chapter 11. Since the
Petition Date, three additional subsidiaries have filed for reorganization
under Chapter 11 of the Bankruptcy Code. International operations and certain
other subsidiaries were not included in the filing. NRG Energy expects
operations to continue as normal during the restructuring process, while it
operates its business as a debtor-in-possession under the jurisdiction of the
Bankruptcy Court and in accordance with the applicable provisions of the
Bankruptcy Code and orders of the Bankruptcy Court. For more information about
NRG Energys restructuring process, refer to the Form 10-K filed by NRG Energy
on March 31, 2003, Form 10-Qs filed by NRG Energy on
May 20, 2003 and August 14, 2003.

The accompanying unaudited consolidated financial statements have been
prepared in accordance with the Securities and Exchange Commission (SEC)
regulations for interim financial information and with the instructions to Form
10-Q. Accordingly, they do not include all of the information and footnotes
required by generally accepted accounting principles for complete financial
statements. The accounting policies followed by the Company are set forth in
Item 15  Note 2 to the Companys financial statements in its annual report on
Form 10-K for the year ended December 31, 2002 (Form 10-K). The following notes
should be read in conjunction with such policies and other disclosures in the
Form 10-K. Interim results are not necessarily indicative of results for a full
year.

The
consolidated
financial statements have been prepared on a going concern basis in
accordance with GAAP. The going concern basis of presentation assumes that
the Company will continue in operation for the foreseeable future and will be
able to realize its assets and discharge its liabilities in the normal course
of business. Because of the Chapter 11 Cases and the circumstances leading to
the filing thereof, the Companys ability to continue as a going concern is
subject to substantial doubt and is dependent upon, among other things,
confirmation of a plan of reorganization, the Companys ability to comply with
the terms of, and if necessary renew at its expiration in May 2004, the Debtor
in Possession Credit Facility, and the Companys ability to generate sufficient
cash flows from operations, asset sales and financing arrangements to meet its
obligations. There can be no assurances that this can be accomplished and if it
were not, the Companys ability to realize the carrying value of its assets and
discharge its liabilities would be subject to substantial uncertainty.
Therefore, if the going concern basis were not used for
the financial
statements, then significant adjustments could be necessary to the carrying
value of assets and liabilities, the revenues and expenses reported, and the
balance sheet classifications used.

The
consolidated
financial statements also have been prepared in accordance with The
American Institute of Certified Public Accountants Statement of Position 90-7
(SOP 90-7), Financial Reporting by Entities in Reorganization under the
Bankruptcy Code.Accordingly, all prepetition liabilities believed to be
subject to compromise have been segregated in the Consolidated Balance Sheet
and classified as liabilities subject to compromise, at the estimated amount of
allowable claims. Liabilities not believed to be subject to compromise are
separately classified as current and non-current. Interest expense is reported
only, subsequent to the petition date, to the extent that it will be paid or
that it is probable that it will be an allowed claim.

During the Chapter 11 Cases, the Debtors may, subject to any necessary
Bankruptcy Court and lender approvals, sell assets and settle liabilities for
amounts other than those reflected in the financial statements. The
administrative and reorganization expenses resulting from Chapter 11 Cases will
unfavorably affect the Debtors results of operations. Future results of
operations may also be adversely affected by other factors related to Chapter
11 Cases.

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The Company is in the process of reconciling recorded prepetition
liabilities with claims filed by creditors with the Bankruptcy
Court. Differences resulting from that reconciliation process will be
recorded as adjustments to prepetition liabilities. The Company recently began
this process and has not yet determined the reorganization adjustments.

In the opinion of management, the accompanying unaudited interim
consolidated financial statements contain all material adjustments necessary to
present fairly the consolidated financial position of the Company as of
September 30, 2003 and December 31, 2002, the results of its operations and
members equity for the three and nine months ended September 30, 2003 and
2002, and its cash flows for the nine months ended September 30, 2003 and 2002.

Certain prior year amounts have been reclassified for comparative
purposes. As previously disclosed, in the Companys 10-K filed on April 14,
2003, the Companys results of operations for the three and nine months ended
September 20, 2002 have been restated to reflect the impairment of the Somerset
facility. This impairment resulted in a $49.3 million change to the Companys
results for the three and nine months ended September 30, 2002.



|1. |  | Restructuring Activities
|-- |  | ------------------------

During 2002, Xcel Energy contributed $500 million to NRG Energy, and NRG
Energy and its subsidiaries sold assets and businesses that provided NRG Energy
in excess of $286 million in cash and eliminated approximately $432 million in
debt. NRG Energy also cancelled or deferred construction of approximately 3,900
MW of new generation projects. On July 26, 2002, Standard & Poors (S&P)
downgraded NRG Energys senior unsecured bonds to below investment grade, and
three days later Moodys also downgraded NRG Energys senior unsecured debt
rating to below investment grade. Currently, NRG Energys unsecured bonds carry
a rating of D at S&P and Ca at Moodys.

In August 2002, NRG Energy retained financial and legal restructuring
advisors to assist its management in the preparation of a comprehensive
financial and operational restructuring. In November 2002, NRG Energy and Xcel
Energy presented a comprehensive plan of restructuring to an ad hoc committee
of its bondholders and a steering committee of its bank lenders (the Ad Hoc
Creditors Committees). The restructuring plan served as a basis for continuing
negotiations between the Ad Hoc Creditors Committees, NRG Energy and Xcel
Energy related to a consensual plan of reorganization for NRG Energy.

On March 26, 2003, Xcel Energy announced that its board of directors had
approved a tentative settlement agreement with holders of most of NRG Energys
long-term notes and the steering committee representing NRG Energys bank
lenders. The terms of the settlement call for Xcel Energy to make payments to
NRG Energy totaling up to $752 million for the benefit of NRG Energys
creditors in consideration for their waiver of any existing and potential
claims against Xcel Energy. Under the settlement, Xcel Energy would make the
following payments: (i) $350 million, up to $150 million of which may be in
Xcel Energy common stock if Xcel Energys public debt fails to maintain a
certain rating, on the later of: (a) 90 days after NRG Energys plan of
reorganization is confirmed by the Bankruptcy Court, and (b) one day after the
effective date of NRG Energys plan of reorganization; (ii) $50 million in the
first quarter of 2004. At Xcel Energys option, it may fill this requirement
with either cash or Xcel Energy common stock or any combination thereof; and
(iii) up to $352 million in April 2004. Since the announcement on March 26,
2003, representatives of NRG Energy, Xcel Energy, the bank lenders and
noteholders continued to meet to draft the definitive documentation necessary
to fully implement the terms and conditions of the tentative settlement
agreement. The final settlement agreement between Xcel Energy and NRG Energy
is subject to the Bankruptcy Court approval including certain provisions and conditions
in its order approving the confirmation of NRG Energys plan of reorganization
and the satisfaction, or waiver by Xcel Energy, of certain other conditions (including
obtaining requisite releases of Xcel Energy by NRG Energy creditors). There can be no
assurance that such conditions will be met.

As noted above, on May 14, 2003, the Debtors filed the Chapter 11 Cases.
NRG Energy expects operations to continue as normal during the restructuring
process, while it operates its business as a debtor-in-possession under the
jurisdiction of the Bankruptcy Court and in accordance with the applicable
provisions of the Bankruptcy Code and orders of the Bankruptcy Court. In
connection with its Chapter 11 filing, NRG Energy also announced that it had
secured a $250 million debtor-in-possession (DIP) financing facility from GE
Capital Corporation, subject to Bankruptcy Court approval, to be utilized by
its NRG Northeast Generating LLC subsidiary ( NRG Northeast) and some NRG
Northeast subsidiaries. The Bankruptcy Court entered an order approving the DIP
facility on July 24, 2003. NRG Energy anticipates that the DIP, together with
its cash reserves and its ongoing revenue stream, will be sufficient to fund
its operations, including payment of employee wages and benefits, during the
negotiation process.

Subsequent to the Petition Date, additional NRG Energy subsidiaries filed
petitions for reorganization with the Bankruptcy Court. On
June 5, 2003, NRG
Nelson Turbines LLC and LSP-Nelson Energy LLC (both wholly owned subsidiaries
of NRG Energy) filed voluntary petitions for reorganization under Chapter 11 of
the Bankruptcy Code in the Bankruptcy Court. On August 19, 2003, NRG

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McClain LLC (a wholly owned subsidiary of NRG Energy) filed a voluntary
petition for reorganization under Chapter 11 of the Bankruptcy Code in the
Bankruptcy Court.

On May 15, 2003, NRG Energy announced that it had been notified that the
New York Stock Exchange (NYSE) has suspended trading in NRG Energys corporate
units that trade under the ticker symbol NRZ (Units) and that an application to
the Securities and Exchange Commission to delist the Units is pending the
completion of applicable procedures, including appeal by NRG Energy of the NYSE
staffs decision. NRG Energy does not plan to make such an appeal. The NYSE
took this action following NRG Energys announcement that it and certain of its
affiliates had filed voluntary positions for reorganization under Chapter
11 of the U.S. Bankruptcy Code.

In
addition, on May 15, 2003, NRG Energy, NRG Power Marketing, Inc.
(NRG PMI),
NRG Finance Company I LLC, NRGenerating Holdings (No. 23) B.V. and NRG Capital
LLC (collectively, the Plan Debtors) filed their Disclosure Statement for
Reorganizing Debtors Joint Plan of Reorganization Pursuant to Chapter 11 of
the United States Bankruptcy Code (as subsequently amended, the Disclosure
Statement). The Bankruptcy Court held a hearing on the Disclosure Statement on
June 30, 2003, and instructed the Plan Debtors to include certain additional
disclosure. The Plan Debtors amended the Disclosure Statement and obtained
Bankruptcy Court approval for the Third Amended Disclosure Statement for
Debtors Second Amended Joint Plan of Reorganization Pursuant to Chapter 11 of
the Bankruptcy Code (respectively, the Amended Disclosure Statement, the Plan)
on October 14, 2003.

The Plan must be approved by the SEC prior to its becoming effective. As
subsidiaries of a registered holding company (Xcel Energy) under the Public
Utility Holding Company Act of 1935 (PUHCA), any reorganization plan for NRG
Energy or NRG Energys subsidiaries must be approved by the SEC prior to such
plan becoming effective. Furthermore, each solicitation of any consent in
respect of any reorganization plan must be accompanied or preceded by a copy of
a report on the plan made by the SEC, or an abstract thereof made or approved
by the SEC. The Plan and Amended Disclosure Statement were submitted to the SEC
for review on July 28, 2003. The SEC issued an order approving the Plan
on October 10, 2003, permitting the Plan Debtors, subject to the approval of
the Bankruptcy Court, to commence solicitation of votes on the Plan.

The Plan Debtors commenced solicitation of votes on the Plan on October
14, 2003. The voting deadline by which holders of claims and equity interests
of the Plan Debtors must submit their ballots accepting or rejecting the Plan
was November 12, 2003. Objections to confirmation of the Plan must be filed
with Bankruptcy Court by November 12, 2003. The Bankruptcy Court has scheduled
the confirmation hearing to determine whether the Plan should be confirmed on
November 21, 2003.

If the Plan is confirmed, holders of NRG Energy unsecured claims
(including bank and bond debt) will receive a combination of New NRG Energy
common stock, New NRG Energy senior notes and cash for an estimated percentage
recovery of 50.7%. Holders of NRG PMI unsecured claims will receive a combination
of New NRG Energy common stock and New NRG Energy senior notes
for an estimated percentage recovery of 44.6%. If the Plan is confirmed,
certain other holders of claims or equity interests in the Plan Debtors will
(i) have their claims paid in full in accordance with the Bankruptcy Code,
(ii) have their claims or equity interests reinstated, or (iii) have their
claims or equity interests cancelled, and receive no distribution on account of
such claims or equity interests. Upon emergence from bankruptcy, Xcel Energys
ownership interest in NRG Energy will be cancelled and ownership in NRG Energy
will vest in the unsecured creditors of NRG Energy and NRG PMI.

On September 17, 2003, NRG Northeast and NRG South Central Generating LLC
(NRG South Central) and certain of their subsidiaries and affiliates filed a
plan of reorganization with the Bankruptcy Court (the NRG Northeast and NRG
South Central Plan). The debtors under the NRG Northeast and NRG South Central
Plan are not soliciting votes for approval of the NRG Northeast and NRG South
Central Plan because none of the holders of claims or equity interests are
impaired under the NRG Northeast and NRG South Central Plan. The Bankruptcy
Court has scheduled a hearing on the confirmation of the NRG Northeast and NRG
South Central Plan on November 21, 24 and 25, 2003.

During the Chapter 11 Cases, the Debtors may, subject to any necessary
Bankruptcy Court and lender approvals, sell assets and settle liabilities for
amounts other than those reflected in the financial statements. The
administrative and reorganization expenses resulting from Chapter 11 Cases will
unfavorably affect the Debtors results of operations. Future results of
operations may also be adversely affected by other factors related to Chapter
11 Cases.

The Company is in the process of reconciling recorded prepetition
liabilities with claims filed by creditors with the Bankruptcy Court.
Differences resulting from that reconciliation process will be recorded as
adjustments to prepetition liabilities. The Company recently began this
process and has not yet determined the reorganization adjustments.

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|2. |  | Debtors Statements
|-- |  | -------------------

As stated above, NRG Energy and certain of its subsidiaries (including NRG
Northeast and its subsidiaries) filed voluntary petitions for reorganization
under Chapter 11 of the Bankruptcy Code on May 14, 2003. As of the bankruptcy
filing date, the Debtors financial records were closed for the prepetition
period. As required by SOP 90-7 Financial Reporting by Entities in
Reorganization under the Bankruptcy Code,below are the condensed combined
financial statements of the Debtors since the date of the bankruptcy filings
(the Debtors Statements). The Debtors Statements have been prepared on the
same basis as NRG Northeasts Consolidated Financial Statements. All entities
of NRG Northeast are included in the bankruptcy filing; therefore the condensed
combined balance sheet is not required under SOP 90-7.

DEBTORS CONDENSED COMBINED STATEMENT OF OPERATIONS

For the three
    
    For the periodmonths ended
    
    from May 15, 2003(In thousands)
    
    September 30, 2003
    
    to September 30, 2003Operating revenue
    
    $
    260,472
    
    
    $
    388,391Operating costs and expenses
    
    
    181,351
    
    
    
    325,614Restructuring professional fees and expenses
    
    
    515
    
    
    
    1,081Operating income
    
    
    78,606
    
    
    
    61,696Restructuring interest income
    
    
    2
    
    
    
    5Other expense, net
    
    
    (14,627
    )
    
    
    (21,833
    )Net income
    
    $
    63,981
    
    
    $
    39,868


DEBTORS CONDENSED COMBINED STATEMENT OF CASH FLOWS

For the periodfrom May 15, 2003(In thousands)
    
    to September 30, 2003Net cash used by operating activities
    
    $
    (11,105
    )Net cash used by investing activities
    
    
    (7,869
    )Net cash used by financing activities
    
    
    Net decrease in cash and cash equivalents
    
    
    (18,974
    )Cash and cash equivalents at beginning of period
    
    
    19,100Cash and cash equivalents at end of period
    
    $
    126




|3. |  | Debt
|-- |  | ----

As of September 30, 2003, NRG Energy has failed to make scheduled payments
on interest and/or principal on approximately $4.0 billion of its recourse debt
and is in default under the related debt instruments. These missed payments
also have resulted in cross-defaults of numerous other non-recourse and limited
recourse debt instruments of NRG Energy. In addition to the missed debt
payments, a significant amount of NRG Energys debt and other obligations
contain terms, which require that they be supported with letters of credit or
cash collateral following a ratings downgrade. As a result of the downgrades
that NRG Energy experienced in 2002, NRG Energy estimates that it is in default
of its obligations to post collateral of approximately $1.2 billion,
principally to fund a $842.5 million equity guarantee associated with its
construction revolver financing facility, to fund debt service reserves and
other guarantees related to NRG Energy projects and to fund trading operations.

Absent an agreement on a comprehensive restructuring plan, NRG Energy will
remain in default under its debt and other obligations, because it does not
have sufficient funds to meet such requirements and obligations. There can be
no assurance that NRG Energys creditors ultimately will accept any consensual
restructuring plan under the bankruptcy process. For more information
about NRG Energys restructuring process, refer to the
Form 10-K filed by NRG Energy on March 31, 2003,
Forms 10-Q filed by NRG Energy on May 20, 2003
August 14, 2003 and November 13, 2003.

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Debtor-in-Possession Loan

NRG Energy and certain of its subsidiaries have negotiated a Senior
Secured, Super-Priority Debtor-in-Possession Credit Agreement (the DIP
Agreement) with General Electric Capital Corporation (GECC), which was executed
following the filing of the petition in NRG Energys Chapter 11 bankruptcy
case. Under the DIP Agreement, GECC has agreed to make up to $250 million (the
DIP Facility) available for working capital and general corporate needs of the
Debtors that comprise NRGs Northeast generating facilities (the DIP
Borrowers). The DIP Facility is secured by a first priority lien on
substantially all of the assets of and equity interest in the DIP Borrowers,
plus the assets of Power Marketing, Inc. that relate to the revenues of the DIP
Borrowers.

The DIP Facility bears an interest rate of 2.00% over the prime rate or
3.50% over the LIBOR rate and is currently set to expire on May 13, 2004. NRG
Energy does not currently anticipate that it will seek to extend the DIP
Facility beyond May 13, 2004. However, should the DIP Facility be extended
for more than one year, approval of such financing by New York Public Service
Commission will be required as certain NRG Energy assets securing the loan are
located in New York. Should such approval be necessary, NRG Energy intends to
make a timely application for the approval.

The amount available under the DIP Facility may vary from time to time,
depending on valuations of the collateral securing the DIP Facility and GECCs
right to set aside certain reserves. The DIP Facility currently permits the DIP
Borrowers to borrow up to $210 million. The total availability may increase to
$250 million upon the occurrence of certain subsequent events. A final order
approving the DIP Facility was entered by the Bankruptcy Court on July 24,
2003. Such order provides, among other things, that the borrowers may not use
DIP funds or cash collateral to make disbursements to, or for the benefit of
the Connecticut Light and Power Company, unless further agreed to by GECC, the
DIP lender, the Official Committee of Unsecured Creditors of NRG Energy, Inc.
et al. and the informal committee of holders of the three series of Senior
Secured Bonds issued by NRG Northeast Generating LLC, or further order of the
Bankruptcy Court

As of September 30, 2003, there was no amount outstanding under the DIP
Facility. As of September 30, 2003, under the DIP Facility, the Company paid a
facility fee of approximately $0.9 million. In addition, the Company pays a
commitment fee based on utilization of the facility of between 0.5% and 1.0% of
the unused commitments of $210 million.

The DIP Facility contains covenants which restrict; mergers and
acquisitions, the incurrence of additional debt, the creation of liens, sale of
stock and assets, sale-leasebacks, cancellation of indebtedness constituting
collateral or subordinated debt, restricted payments, speculative transactions,
maximum annual capital expenditures and minimum quarterly earnings as outlined
in the DIP Agreement.

In addition, the DIP Facility includes the following reporting covenants;
provide monthly financial statements and operating reports within 30 days,
provide quarterly financial statements and operating reports within 45 days,
provide annual audited financial statements within 90 days of the end of the
Companys fiscal year; provide operating plan within 30 days of fiscal year
end, provide management letter and notices described in the DIP Agreement when
available or as reasonable requested by the DIP Lenders.



|4. |  | Inventory
|-- |  | ---------

Inventory
consisted of spare parts, coal, fuel oil and kerosene and is
stated at the lower of weighted average cost or market value:

(In thousands)
    
    September 30, 2003
    
    December 31, 2002Fuel oil
    
    $
    64,609
    
    
    $
    47,052Spare parts
    
    
    49,923
    
    
    
    59,524Coal
    
    
    12,692
    
    
    
    14,378Kerosene
    
    
    2,623
    
    
    
    2,852Other
    
    
    328
    
    
    
    157Total
    
    $
    130,175
    
    
    $
    123,963




|5. |  | Property, Plant and Equipment
|-- |  | -----------------------------

Property, plant and equipment are stated at cost or recoverable value.
Depreciation is computed on a straight-line basis over the following estimated
useful lives:

Facilities, machinery and equipment
    
    
    7 to 30 yearsOffice furnishings and equipment
    
    
    3 to 10 years


Property, plant and equipment consisted of:

(In thousands)
    
    September 30, 2003
    
    December 31, 2002Facilities, machinery and equipment
    
    $
    1,153,565
    
    
    $
    1,415,726Land
    
    
    46,905
    
    
    
    46,925Construction in progress
    
    
    17,542
    
    
    
    27,615Office furnishings and equipment
    
    
    1,195
    
    
    
    1,196Accumulated depreciation
    
    
    (163,139
    )
    
    
    (157,534
    )Property, plant and equipment, net
    
    $
    1,056,068
    
    
    $
    1,333,928


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In light of economic developments related to the Connecticut assets and
NRG Energys application for cost of service reimbursements, The Company
reassessed the asset lives for the Connecticut facilities. The shorter
depreciable lives resulted in an increase in depreciation of approximately $0.7
million and $13.9 million for the three and nine months ended September 30,
2003. In accordance with SFAS No. 144, the Company has reclassified the
accumulated depreciation recorded on those facilities that were impaired during
the nine and twelve months ended September 30, 2003 and December 31, 2002,
respectively.



|6. |  | Accounting for Long-Term Contracts
|-- |  | ----------------------------------

On June 18, 2003, the Company terminated an indemnity agreement between
itself and NRG PMI, effective to May 14, 2003. Upon the
effective termination of this agreement, certain outstanding trade receivables
were transferred from the Company to NRG PMI. This transfer resulted in a
balance sheet reclass of approximately $67.4 million on the Companys
financials from accounts receivable  trade to accounts receivable  affiliate.
These receivables relate to three long-term contracts that were directly
affected by the termination of this indemnity agreement. As a
result, the Company will no longer recognize any revenues or expenses related
to these contracts. The affected contracts were the Standard Offer Service
contract with CL&P, a long-term contract with Ashland and a long- term contract
with EUA. Effective May 14, 2003, NRG PMI will bear the benefits and burdens of
these contracts. During the period prior to May 14, 2003 (January 1, 2003  May
14, 2003), the provisions of the standard offer contracts resulted in an actual
operating loss for the Companys Connecticut facilities of approximately $105.9
million.

In addition, effective with the indemnity agreement termination, the
Company has reclassified certain other accounts receivable  trade balances to
accounts receivable  affiliate to recognize the related party relationship
between NRG PMI and the Company and its subsidiaries. As of June 30, 2003,
approximately $1.7 million of accounts receivable  trade was reclassified to
accounts receivable  affiliate. The ongoing expense and revenue recognition
related to these transactions will remain consistent with the Companys past
policies and procedures. Included in operating revenue is approximately $256.8
million and $314.1 million of related party revenue for the three and nine
month periods ending September 30, 2003.



|7. |  | Derivative Instruments and Hedging Activity
|-- |  | -------------------------------------------

On January 1, 2001, the Company adopted Statement of Financial Accounting
Standards No. 133, Accounting for Derivative Instruments and Hedging Activities
(SFAS No. 133), as amended by SFAS No. 137 and SFAS No. 138. SFAS No. 133
requires the Company to record all derivatives on the balance sheet at fair
value. Changes in the fair value of non-hedge derivatives are immediately
recognized in earnings. Derivatives that have been designated as hedges of
assets, liabilities or firm commitments, are accounted for using the fair value
method. Changes in the fair value of these instruments are recognized in
earnings as offsets to the changes in the fair value of the related hedged
assets, liabilities and firm commitments. Derivatives that have been designated
as hedges of forecasted transactions are accounted for using the cash flow
method. Changes in the fair value of these instruments are deferred and
recorded as a component of accumulated other comprehensive income (OCI) until
the hedged transactions occur and are recognized in earnings. Reclassifications
of the deferred gains and losses are included on the same line of the statement
of operations in which the hedged item is recorded. The ineffective portion of
the change in fair value of a derivative instrument designated as a cash flow
hedge is immediately recognized in earnings. The Company formally assesses both
at inception and at least quarterly thereafter, whether the derivatives used in
hedging transactions are highly effective in offsetting the changes in either
the fair value or cash flows of the hedged item. This assessment includes all
components of each derivatives gain or loss unless otherwise noted. When it is
determined that a derivative ceases to be a highly effective hedge, hedge
accounting is discontinued.

SFAS No. 133 applies to the Companys long-term power sales contracts,
long-term gas purchase contracts and other energy related commodities financial
instruments used to mitigate variability in earnings due to fluctuations in
spot market prices, hedge fuel

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##### Table of Contents



requirements at generation facilities and protect investments in fuel
inventories. At September 30, 2003, the Company had derivative contracts
extending through December 2003.

Accumulated Other Comprehensive Income

The following table summarizes the effects of SFAS No. 133 on the
Companys OCI balance:

Three Months Ended
    
    Nine Months EndedGains/(Losses)
    
    September 30,
    
    September 30,(In thousands)
    
    2003
    
    2002
    
    2003
    
    2002Beginning Balance
    
    $
    
    
    
    $
    66,772
    
    
    $
    28,835
    
    
    $
    107,741Unwound from OCI during period:-
due to unwinding of
previously deferred amounts
    
    
    
    
    
    
    (2,854
    )
    
    
    (28,835
    )
    
    
    (6,779
    )Mark to market hedge contracts
    
    
    
    
    
    
    21,889
    
    
    
    
    
    
    
    (15,155
    )Ending Balance
    
    $
    
    
    
    $
    85,807
    
    
    $
    
    
    
    $
    85,807Gains/(Losses) expected to
unwind from OCI during next 12
months
    
    $
    
    
    
    $
    85,807
    
    
    $
    
    
    
    $
    85,807


Gains of $0 and $28.8 million were reclassified from OCI to current period
earnings during the three and nine months ended September 30, 2003 due to the
unwinding of one long-term energy commodity contract accounted for as a cash
flow hedge, which expired June 30, 2003. In comparison for the three and nine
months ended September 30, 2002 gains of approximately $2.9 million and $6.8
million were reclassified. These amounts are recorded on the same line item in
the statement of operations in which the hedged items are recorded. During the
three and nine months ended September 30, 2003, the Company recorded no amounts
in OCI related to changes in the fair values of derivatives accounted for as
hedges. For the three and nine months ended September 30, 2002 the Company
recorded a gain of $21.9 million and a loss of $15.2 million respectively in
OCI, related to changes in the fair values of derivatives accounted for as
hedges. The net balance in OCI relating to SFAS No. 133 as of September 30,
2003 was $0. The Company expects no deferred net gains on derivative
instruments accumulated in OCI to be recognized as earnings during the next
twelve months.

Statement of Operations

The following table summarizes the effects of SFAS No. 133 on the
Companys statement of operations:

Three Months Ended
    
    Nine Months EndedGains/(Losses)
    
    September 30,
    
    September 30,(In thousands)
    
    2003
    
    2002
    
    2003
    
    2002Revenues
    
    $
    (3,219
    )
    
    $
    (35,344
    )
    
    $
    17,933
    
    
    $
    (771
    )Operating costs
    
    
    (112
    )
    
    
    (17,427
    )
    
    
    (1,556
    )
    
    
    (7,843
    )Total statement of operations impact
    
    $
    (3,331
    )
    
    $
    (52,771
    )
    
    $
    16,377
    
    
    $
    (8,614
    )


During the three and nine months ended September 30, 2003 and 2002, the
Company recognized no gain or loss due to ineffectiveness of commodity cash
flow hedges.

The Companys earnings for the three months ended September 30, 2003 and
2002 were decreased by an unrealized loss of $3.3 million and $52.8 million,
respectively. For the nine months ended September 30, 2003 and 2002 the
companys earnings changed by an unrealized gain of $16.4 million and an
unrealized loss of $8.6 million, respectively, associated with changes in the
fair value of energy related derivative instruments not accounted for as hedges
in accordance with SFAS No. 133.



|8. |  | Regulatory Issues
|-- |  | -----------------

NRG Energy is impacted by market rule and tariff changes in the existing
markets operated by Independent System Operators (ISOs) and Regional
Transmission Organizations (RTOs).

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On March 1, 2003, ISO-New England implemented its version of Standard
Market Design. This change dramatically modifies the New England market
structure by incorporating Locational Marginal Pricing (pricing by location
rather than on a New England wide basis). While the ISO-New England Standard
Market Design represents a significant improvement to the existing market
design, NRG Energy still considered the market insufficient to allow NRG Energy
to recover its reasonable costs and earn a reasonable return on investment.
Therefore, and notwithstanding the impending implementation of Locational
Marginal Pricing, on February 26, 2003, NRG Energy filed a proposed cost of
service agreement with the Federal Energy Regulatory Commission (FERC) for the
following Connecticut facilities: Middletown Power LLC, Montville Power LLC,
Norwalk Power LLC and Devon Power LLC units 11-14 (collectively the NRG
Subsidiaries). In the filing, NRG Energy requested that major and minor
maintenance expenses of the NRG Subsidiaries be paid for through a tracking
mechanism that would insure that NRG Energy receives compensation only for
actual maintenance expenses. Under the proposed cost of service agreement, the
other NRG Energy costs would be paid through a monthly cost-based payment. NRG
Energy requested an effective date of February 27, 2003.

On March 25, 2003, FERC issued an order (the March Order) approving the
recovery of the NRG Subsidiaries Spring 2003 maintenance expenses, subject to
refund and authorized an effective date of February 27, 2003. FERC did not rule
on the remainder of the issues to allow further time to consider protests.

On April 25, 2003, the FERC issued an order (the April Order) rejecting
the remaining part of the proposed cost of service agreements including the
monthly cost-based payment. Rather, FERC instructed ISO New England to
establish temporary bidding rules that would permit selected peaking units
(units with capacity factors of 10 percent or less during 2002), operating
within designated congestion areas (such as Connecticut) to raise their bids
to allow them the opportunity to recover their fixed and variable costs through
the market. This temporary bidding rule would remain in place until ISO New
England implements locational installed capacity requirements, which should be
no later than June 1, 2004. In the July 24 Order on Rehearing (the July Order),
FERC clarified that the capacity factor of 10 percent or less applies to units
rather than complexes. On a unit basis, all the NRG Energy facilities qualify
to bid under the temporary rules except Middletown 2 and 3, and Devon 7 and 8.
The existing Reliability Must Run (RMR) agreement between ISO New England and
NRG Energy covering Devon 7 and 8 terminated on September 30, 2003. On October
2, 2003, NRG Energy filed to extend the existing RMR agreement. FERC has yet to
act on the request to extend the agreement. For additional information
regarding the impact that the April 25, 2003 FERC order and other regulatory
developments had on NRG Energys results of operations, See Note
10.

On October 17, 2003, the Midwest Independent Transmission Operator, Inc.
(MISO) filed a motion to withdraw its Open Access Transmission and Energy
Markets Tariff (TEMT), purportedly to allow more time to develop stakeholder
consensus on critical outstanding issues relating to market features such as
Fixed Transmission Rights, market monitoring and resource adequacy.
Post-blackout reliability concerns were also a stated factor for the
withdrawal. On October 29, 2003, FERC granted the MISOs motion. The MISO had
planned to phase-in its energy markets during 2004. The withdrawal of the
market tariff means that the market will be delayed for an undetermined period
of time.



|9. |  | Commitments and Contingencies
|-- |  | -----------------------------

Litigation

The New York Voluntary Bankruptcy Case

On
May 14, 2003, NRG Energy and certain of its affiliates (including
NRG Northeast) filed voluntary petitions for reorganization under Chapter 11 of
the United States Bankruptcy Code (the Bankruptcy Code) in the United States
Bankruptcy Court for the Southern District of New York (the Bankruptcy Court),
In re: NRG ENERGY, INC., et. al., Case No. 03-13024 (PCB). NRG Energy expects
operations to continue as normal during the restructuring process, while it
operates its business as a debtor-in-possession under the jurisdiction of the
Bankruptcy Court and in accordance with the applicable provisions of the
Bankruptcy Code and orders of the Bankruptcy Court.

Fortistar Capital Inc. v. NRG Energy, Inc., Hennepin County District Court

On July 12, 1999, Fortistar Capital Inc. (Fortistar) sued NRG Energy in
Minnesota state court. The complaint sought injunctive relief and damages of
over $50 million resulting from NRG Energys alleged breach of a letter
agreement with Fortistar relating to the

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##### Table of Contents



Oswego power plant. NRG Energy asserted counterclaims. After considerable
litigation, the parties entered into a conditional, confidential settlement
agreement, which was subject to necessary board and lender approvals. NRG
Energy was unable to obtain necessary approvals. Fortistar initially moved the
court to enforce the settlement, seeking damages in excess of $35 million plus
interest and attorneys fees. NRG Energy opposed Fortistars motion on the
grounds that conditions to contract performance had not been satisfied. In
July 2003, Fortistar purported to withdraw its motion without prejudice and
sought relief from stay at the Bankruptcy Court to liquidate its bankruptcy
claim by trying the action in the Minnesota State Court. The Bankruptcy Court
denied Fortistars relief from stay motion and Fortistar is now seeking relief
and review at the United States District Court for the Southern District of New
York. NRG Energy cannot predict the outcome of this dispute.

Connecticut Light & Power Company v. NRG Power Marketing Inc., Docket No.
3:01-CV-2373 (A WT), pending in the United States District Court, District of
Connecticut

This matter involves a claim by Connecticut Light & Power Company for
recovery of amounts it claims are owing for congestion charges under the terms
of a Standard Offer Services contract between the parties, dated October 29,
1999. CL&P has served and filed its motion for summary judgment to which NRG
Power Marketing Inc. (NRG PMI) filed a response on March 21, 2003. CL&P has
withheld approximately $30 million from amounts owed to NRG PMI, claiming that it
has the right to offset those amounts under the contract. NRG PMI has
counterclaimed seeking to recover those amounts, arguing among other things
that CL&P has no rights under the contract to offset them. By reason of the
bankruptcy stay, the court has not ruled on the pending motion. On November 6,
2003, the parties filed a joint stipulation for relief from the automatic stay
in order to allow the proceeding to go forward. NRG PMI cannot estimate at this
time the likelihood of an unfavorable outcome in this matter, or the overall
exposure for congestion charges for the full term of the contract.

Connecticut Light & Power
Company, Docket No. EL03-135, pending at the Federal
Energy Regulatory Commission

This matter involves a dispute between CL&P and NRG PMI concerning which of
those parties is responsible, under the terms of the October 29, 1999 Standard
Offer Services contract, for costs related to congestion and losses associated
with the implementation of standard market design (SMD-Related Costs). CL&P
has withheld, beyond the $30 million discussed above, an additional
approximately $70 million from amounts owed to NRG PMI, claiming that it is
entitled under the contract to offset those additional amounts for SMD-Related
Costs. NRG PMI cannot estimate at this time the likelihood of an unfavorable
outcome in this matter, or the overall exposure for SMD-Related Costs for the
full term of the contract.

Connecticut Light & Power  Related Proceedings at the Federal Energy
Regulatory Commission, the United States District Court for the Southern
District of New York, and the United States Court of Appeals for the D.C.
Circuit and the Second Circuit.

In May, 2003, NRG PMI took steps to terminate or reject in bankruptcy the
subject Standard Offer Services contract. CL&P, the Connecticut Attorney
General and the Connecticut Department of Public Utility Control (DPUC)
sought and obtained from FERC an Order dated May 16, 2003, temporarily
requiring NRG PMI to continue to comply with the terms of the contract, pending
further notice from FERC. Thereafter, On June 2, 2003, the United States
Bankruptcy Court for the Southern District of New York issued its Order
specifically authorizing NRG PMIs rejection of the contract, and by Order dated
June 12, 2003, the United States District Court for the Southern District of
New York granted NRG PMIs motion for a temporary restraining order staying all
actions by CL&P, the Connecticut Attorney General and the DPUC to enforce or
apply the above-referenced FERC Order and affording NRG PMI leave to cease its
performance under the contract, effective retroactive to June 2, 2003. FERC
then issued an order on June 25, 2003 (June 25 Order), that again commanded
NRG PMIs continued performance regardless of any contrary ruling by the Bankruptcy
Court and the District Courts temporary restraining order. By order dated
June 30, 2003, the District Court reversed itself and dismissed NRG PMIs motion
for preliminary injunction for lack of subject matter jurisdiction. On July
18, 2003, NRG PMI appealed to the Second Circuit respecting the District Courts
refusal to enjoin FERC. On August 15, 2003, FERC issued orders denying
rehearing of the June 25 Order and requiring NRG PMI to continue to perform under
the Standard Offer Services contract (the June 25 Order, together with the
August 15 Orders, the Commission Orders). NRG PMI filed a request for rehearing
with FERC and a petition for review in the United States Court of Appeals for
the District of Columbia Circuit in Case No. 03-1346 relating to the Commission
Orders. On November 4, 2003, the parties reached a settlement under which the
Second Circuit and D.C. Circuit litigation respecting the above matters will be
dismissed, while preserving the parties rights to litigate those matters which
are before the United States District Court for the District of Connecticut and
FERC, as previously discussed. The settlement does not affect issues between
CL&P and NRG Energy, Inc., related to station service, described hereafter,
which will be separately arbitrated. The settlement is subject to regulatory
and legal approvals, including approval from FERC and the United States
Bankruptcy Court for the Southern District of New York.

The State of New York and Erin M. Crotty, as Commissioner of the New York State
Department of Environmental Conservation v. Niagara Mohawk Power Corporation et
al.,United States District Court for the Western District of New York, Civil
Action No. 02-CV-002S

In January 2002, NRG Energy and Niagara Mohawk Power Corporation (NiMo)
were sued by the New York Department of Environmental Conservation in federal
court in New York. The complaint asserted that projects undertaken at NRG
Energys Huntley and Dunkirk plants by NiMo, the former owner of the
facilities, required preconstruction permits pursuant to the Clean Air Act and
that the failure to obtain these permits violated federal and state laws. In
July 2002, NRG Energy filed a motion to dismiss. On March 27, 2003 the court
dismissed the complaint against NRG Energy with prejudice as to the federal
claims and without prejudice as to the state claims. It is possible the state
will appeal this dismissal to the Second Circuit Court of Appeals. In the
meantime, on April 25, 2003, the state provided to NRG Energy notice of intent
to again sue the Company and various affiliates by filing a second amended
complaint in this same action in the federal court in New York, asserting
against the NRG Defendants violations of operating permits and deficient
operating permits at the Huntley and Dunkirk plants. The NRG Defendants have
moved to dismiss the second amended

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##### Table of Contents



complaint, and that motion is now under advisement. If the case
ultimately is litigated to a judgment and there is an unfavorable outcome that
could not be addressed otherwise, NRG Energy has estimated that the total
investment that would be required to install pollution control devices could be
as high as $300 million over a ten to twelve-year period.

Niagara Mohawk Power Corporation v. NRG Energy, Inc., Huntley Power, LLC, and
Dunkirk Power, LLC,Supreme Court, State of New York, County of Onondaga, Case
No. 2001-4372

NRG Energy has asserted that NiMo is obligated to indemnify it for any
related compliance costs associated with resolution of the above enforcement
action. NiMo has filed suit in state court in New York seeking a declaratory
judgment with respect to its obligations to indemnify NRG Energy under the
asset sales agreement. NRG Energy has pending a summary judgment motion on its
entitlement to be reimbursed by NiMo for the attorneys fees NRG Energy has
incurred in the enforcement action.

Huntley Power LLC, Dunkirk Power LLC and Oswego Power LLC

All three of these facilities have been issued Notices of Violation with
respect to opacity exceedances. The above entities have been engaged in consent
order negotiations with the New York State Department of Environmental
Conservation (DEC) relative to opacity issues affecting all three facilities
since the plants were acquired. It appears that by year-end, the parties will
finalize the terms of a consent order, which will quantify the number of
opacity exceedances at the three facilities through the second quarter of 2003
and set a cumulative penalty, presently anticipated to be some $1 million. In
the event that the consent order negotiations prove unsuccessful, it is not
known what relief the DEC will seek through an enforcement action and what the
result of such action will be.

Huntley Power LLC

On April 30, 2003, the Huntley Station submitted a self-disclosure letter
to the New York Department of Environmental Conservation (DEC) reporting
violations of applicable sulfur in fuel limits, which had occurred during 6
days in March 2003 at the chimney stack serving Huntley Units 63-66. The
Huntley Station self-disclosed that the average sulfur emissions rates for
those days had been 1.8 lbs/mm BTU, rather than the maximum allowance of 1.7
lbs/mm BTU. NRG Huntley Operations discontinued use of Unit 65 (the only unit
utilizing the subject stack at the time) and has kept the remaining 3 units off
line until adherence with the applicable standard is assured. On May 19, 2003,
the DEC issued Huntley Power LLC a Notice of Violation. The Company has met
with the DEC to discuss the circumstances surrounding the event and the
appropriate means of resolving the matter. The Company does not know what
relief the DEC will seek through an enforcement action. Under applicable
provisions of the Environmental Conservation Law, the DEC asserts that it may
impose a civil penalty up to $10,000, plus an additional penalty not to
exceed $10,000 for each day that a violation continues and may enjoin
continuing violations.

Niagara Mohawk Power Corporation v. Dunkirk Power LLC, et al., Supreme Court,
Erie County, Index No. 1-2000-8681

On October 2, 2000, plaintiff Niagara Mohawk Power Corporation commenced
this action against NRG Energy to recover damages plus late fees, less payments
received through the date of judgment, as well as any additional amounts due
and owing, for electric service provided to the Dunkirk Plant after September
18, 2000. Plaintiff Niagara Mohawk claims that NRG Energy has failed to pay
retail tariff amounts for utility services commencing on or about June 11, 1999
and continuing to September 18, 2000 and thereafter. Plaintiff has alleged
breach of contract, suit on account, violation of statutory duty, and unjust
enrichment claims. On or about October 23, 2000, NRG Energy served an answer
denying liability and asserting affirmative defenses.

After proceeding through discovery, and prior to trial, the parties and
the court entered into a stipulation and order filed August 9, 2002
consolidating this action with two other actions against NRG Northeasts
Huntley and Oswego subsidiaries, both of which cases assert the same claims and
legal theories for failure to pay retail tariffs for utility services.

On October 8, 2002, a Stipulation and Order was filed in the Erie County
Clerks Office staying this action pending submission of some or all of the
disputes in the action to the FERC. NRG Energy cannot make an evaluation of the
likelihood of an unfavorable outcome. The cumulative potential loss could
exceed $35 million.

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Niagara Mohawk Power Corporation v. Huntley Power LLC, NRG Huntley Operations,
Inc., NRG Dunkirk Operations, Inc., Dunkirk Power LLC, Oswego Harbor Power LLC,
and NRG Oswego Operations, Inc., Case Filed November 26, 2002 in Federal Energy
Regulatory Commission Docket No. EL 03-27-000.

This is the companion action filed by Niagara Mohawk at FERC, similarly
asserting that Niagara Mohawk is entitled to receive retail tariff amounts for
electric service provided to the Huntley, Dunkirk and Oswego plants. On
October 31, 2003, the FERC Trial Staff, a party to the proceedings, filed a
reply brief in which they supported and agreed with each position taken by the
NRG Generators in their initial brief. In short, the staff argued that the NRG
Generators: (1) self-supply station power under the NYISO tariff (which took
effect on April 1, 2003), in any month during which they produce more energy
than they consume and, as such should not be assessed a retail rate; (2) are
connected only to transmission facilities and as such, at most should only pay
NiMo a FERC-approved transmission rate; and (3) should be allowed to net
consumption and output even if power is injected into the grid at a different
point from which it is drawn off. The parties are currently engaged in
settlement negotiations which, should they prove successful, will resolve both
this FERC action and the above-referenced state court proceedings respecting
amounts owing for electrical service provided to these three plants. At this
stage of the proceedings, we cannot estimate the likelihood of an adverse
determination. As noted above, the cumulative potential loss could exceed $35
million.

NRG Energy Credit Defaults

NRG Energy and various of its subsidiaries are in default under various of
their credit facilities, financial instruments, construction agreements and
other contracts, which have given rise to liens, claims and contingencies
against them and may in the future give rise to additional liens, claims and
contingencies against them. In addition, NRG Energy and various of its
subsidiaries have entered into various guarantees, equity contribution
agreements, and other financial support agreements with respect to the
obligations of their affiliates, which have given rise to liens, claims and
contingencies against them and may in the future give rise to additional liens,
claims and contingencies against the party or parties providing the financial
support. NRG Energy cannot predict the outcome or financial impact of these
matters.

Guarantees

The Company is directly liable for the obligations of certain of its
subsidiaries pursuant to guarantees relating to certain of their operating
obligations. In addition, in connection with the purchase and sale of fuel,
emission credits and power generation products to and from third parties with
respect to the operation of some of the Companys generation facilities in the
United States, the Company may be required to guarantee a portion of the
obligations of certain of its subsidiaries. As of September 30, 2003, the
Companys obligations pursuant to its guarantees of the performance of its
subsidiaries totaled approximately $35.3 million.



|10. |  | Restructuring and Impairment Charges
|--- |  | ------------------------------------

As a result of the changing operational, regulatory and financial
conditions impacting the Company on an ongoing basis, the Company reviews the
recoverability of its long-lived assets in accordance with the guidelines of
SFAS No. 144. As a result of this review, the Company recorded asset impairment
charges of $9.0 million for the three months ended September 30, 2003 and
$230.6 million for the nine months ended September 30, 2003, as shown in the
table below.

To determine whether an asset was impaired NRG Northeast compared asset
carrying values to total future estimated undiscounted cash flows. Separate
analyses were completed for assets or groups of assets at the lowest level for
which identifiable cash flows were largely independent of the cash flows of
other assets and liabilities. The estimates of future cash flows included only
future cash flows, net of associated cash outflows, directly associated with
and expected to arise as a result of the Companys assumed use and eventual
disposition of the asset. Cash flow estimates associated with assets in service
were based on the assets existing service potential. The cash flow estimates
may include probability weightings to consider possible alternative courses of
action and outcomes, given the uncertainty of available information and
prospective market conditions.

If an asset was determined to be impaired based on the cash flow testing
performed, an impairment loss was recorded to write down the asset to its fair
value. Estimates of fair value were based on prices for similar assets and
present value techniques. Fair values determined by similar asset prices
reflect the Companys current estimate of recoverability from expected
marketing of project assets. For fair values determined by projected cash
flows, the fair value represents a discounted cash flow amount over the
remaining life of each project that reflects project-specific assumptions for
long-term power pool prices, escalated future project operating costs, and
expected plant operation given assumed market conditions.

Asset impairments and restructuring charges from continuing operations
included in operating expenses in the Consolidated Statements of Operations
include the following:

Three Months Ended
    
    Three Months Ended
    
    Nine Months Ended
    
    Nine Months Ended(In thousands)
    
    September 30, 2003
    
    September 30, 2002
    
    September 30, 2003
    
    September 30, 2002Impairment charges
    
    $
    9,049
    
    
    $
    49,289
    
    
    $
    230,570
    
    
    $
    49,289Restructuring charges
    
    
    554
    
    
    
    
    
    
    
    2,846
    
    
    
    Total
    
    $
    9,603
    
    
    $
    49,289
    
    
    $
    233,416
    
    
    $
    49,289


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Asset impairments for the three months ended September 30, 2003:

Pre-taxProject Name
    
    Project Status
    
    Charge
    
    Fair Value Basis(In thousands)Arthur Kill Power, LLC
    
    Terminated
    
    $
    9,049
    
    
    Projected cash flowsTotal Asset
Impairment Charges
    
    
    
    
    
    $
    9,049


Asset impairments for the nine months ended September 30, 2003:

Pre-taxProject Name
    
    Project Status
    
    Charge
    
    Fair Value Basis(In thousands)Devon Power LLC
    
    Operating at a loss
    
    $
    64,198
    
    
    Projected cash flowsMiddletown Power LLC
    
    Operating at a loss
    
    
    157,323
    
    
    Projected cash flowsArthur Kill Power, LLC
    
    Terminated
    
    
    9,049
    
    
    Projected cash flowsTotal Asset
Impairment Charges
    
    
    
    
    
    $
    230,570


Connecticut Facilities- NRG Energy reviewed cash flow models for its
Connecticut generating facilities at December 31, 2002. No impairment was
required based on the pricing and cost recovery assumptions at December 31,
2002. On February 26, 2003 NRG Energy filed a proposed cost of service
agreement for the following Connecticut facilities with the Federal Energy
Regulatory Commission (FERC) Devon 11-14, Middletown station, Montville
station, Norwalk Harbor station. On April 25, 2003, the FERC issued an order
that rejected NRG Energys proposed fixed monthly charges, citing certain
policy determinations regarding cost-of-service agreements. FERC instead
directed NRG Energy to recover its fixed and variable costs under interim
bidding rules for generators located in constrained areas, the so-called
Peaking Unit Safe Harbor (PUSH) mechanism. The PUSH bidding rules would apply
to all of NRG Energys Connecticut facilities that filed the proposed cost of
service agreements, with the exception of Middletown Units 2 and 3, until June
1, 2004. The following quick start facilities, located in Connecticut also have
submitted PUSH bids that have been approved by FERC: Cos Cob, Franklin Drive,
Branford and Torrington. FERC also ordered that the regional power agencies
overseeing the energy markets in Connecticut, the Independent System Operator
for New England (ISO-NE) and the New England Power Pool (NEPOOL), modify the
New England market rules to establish and implement locational capacity or
deliverability requirements no later than June 1, 2004. In late May and June
2003, ISO-NE revised its market pricing rules to facilitate FERCs mandated
PUSH mechanism, but has not yet proposed the market modifications required to
implement locational capacity or deliverability requirements. In June 2003 NRG
Energy filed for rehearing of several elements of FERCs April 25, 2003 order.
In response, on July 25, 2003, FERC re-affirmed the PUSH interim pricing
mechanism.

The existing RMR between ISO-NE and NRG Energy covering Devon 7 and 8
terminated on September 30, 2003. On October 2, 2003, NRG filed to extend the
existing RMR agreements. A number of protests have been filed and FERC has yet
to act on the request to extend the agreements.

As a result of these regulatory developments and changing circumstances in
the second quarter of 2003, NRG Energy updated the facilities cash flow models
to incorporate changes to reflect the impact of the April 25, 2003 FERCs
orders on PUSH pricing, the pending termination of the RMR, and to update the
estimated impact of future locational capacity or deliverability requirements.
Based on these revised cash flow models, management determined that the new
estimates of pricing and cost recover levels were not projected to return
sufficient revenue to cover the fixed costs at Devon Power LLC and Middletown
Power LLC. As a consequence, during the second quarter of 2003 NRG Energy
recorded a $64.2 million and $157.3 million impairment at Devon Power LLC and
Middletown Power LLC, respectively. NRG Energy accounts for the results of
operations of the Connecticut Facilities as part of its power generation
segment within North America.

Arthur Kill Power, LLC- During the third quarter of 2003 NRG Energy cancelled
its plans to re-establish fuel oil capacity at its Arthur Kill plant. This
resulted in a charge of approximately $9.0 million to write-off assets under
development.

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Credit rating downgrades, defaults under certain credit agreements,
increased collateral requirements and reduced liquidity experienced by the
Company during the third quarter of 2002 were triggering events which
required NRG Northeast to review the recoverability of its long-lived assets.
Adverse economic conditions resulted in declining energy prices. As a result,
the Company determined that Somerset Power, became impaired during the third
quarter of 2002 and should be written down to fair market value. During 2002,
the Company recorded impairment charges of $49.3 million.

During
the three and nine month periods ended September 30, 2003, the
Company incurred $0.5 million and $2.8 million, respectively, of restructuring
costs consisting of advisor fees. These costs consist of employee separation
costs and advisor fees. There were no restructuring costs during 2002.



11. Asset Retirement Obligation

Effective January 1, 2003, the Company adopted SFAS No. 143, Accounting
for Asset Retirement Obligations(SFAS No. 143). SFAS No. 143 requires an
entity to recognize the fair value of a liability for an asset retirement
obligation in the period in which it is incurred. Upon initial recognition of a
liability for an asset retirement obligation, an entity shall capitalize an
asset retirement cost by increasing the carrying amount of the related
long-lived asset by the same amount as the liability. Over time, the liability
is accreted to its present value each period, and the capitalized cost is
depreciated over the useful life of the related asset. Retirement obligations
associated with long-lived assets included within the scope of SFAS No. 143 are
those for which a legal obligation exists under enacted laws, statutes and
written or oral contracts, including obligations arising under the doctrine of
promissory estoppel.

The Company has identified certain retirement obligations at Somerset
Power LLC, a wholly owned subsidiary of the Company, related primarily to
future environmental obligations. The Company has also identified other asset
retirement obligations that could not be calculated because the assets
associated with the retirement obligations were determined to have an
indeterminate life. The adoption of SFAS No. 143 resulted in recording a $0.2
million increase to property, plant and equipment and a $0.3 million increase
to other long-term obligations. The cumulative effect of adopting SFAS No. 143
was approximately a $0.1 million increase to depreciation expense and
approximately a $0.1 million increase to operating expenses.

The following represents the balances of the asset retirement obligation
as of January 1, 2003 and the additions and accretion of the asset retirement
obligation for the nine months ended September 30, 2003:

Accretion NineBeginning Balance
    
    Months Ended
    
    Ending Balance(In thousands)
    
    Jan. 1, 2003
    
    September 30, 2003
    
    September 30, 2003Somerset Power LLC
    
    $
    313
    
    
    $
    32
    
    
    $
    345Total
    
    $
    313
    
    
    $
    32
    
    
    $
    345


The following represents the pro-forma effect on the Companys net income
for the three and nine months ended September 30, 2002, as if the Company had
adopted SFAS No. 143 as of January 1, 2002:

Three Months EndedSeptember 30, 2002(In thousands)Net income as reported
    
    $
    19,787Pro-forma adjustment to reflect retroactive adoption of
SFAS No. 143
    
    
    (14
    )Pro-forma net income
    
    $
    19,773


Nine Months EndedSeptember 30, 2002(In thousands)Net income as reported
    
    $
    68,680Pro-forma adjustment to reflect retroactive adoption of
SFAS No. 143
    
    
    (173
    )Pro-forma net income
    
    $
    68,507


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12. Recent Accounting Pronouncements

In April 2002, the FASB issued SFAS No. 145, Rescission of FASB
Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections,that supersedes previous guidance for the reporting of gains and
losses from extinguishment of debt and accounting for leases, among other
things. SFAS No. 145 requires that only gains and losses from the
extinguishment of debt that meet the requirements for classification as
Extraordinary Items, as prescribed in Accounting Practices Board Opinion No.
30, should be disclosed as such in the financial statements. Previous guidance
required all gains and losses from the extinguishment of debt to be classified
as Extraordinary Items. This portion of SFAS No. 145 is effective for fiscal
years beginning after May 15, 2002, with restatement of prior periods required.
The Company adopted this standard as of January 1, 2003 and has no
extraordinary gains or losses that will require restatement.

In addition, SFAS No. 145 amends SFAS No. 13, Accounting for Leases,as
it relates to accounting by a lessee for certain lease modifications. Under
SFAS No. 13, if a capital lease is modified in such a way that the change gives
rise to a new agreement classified as an operating lease, the assets and
obligation are removed, a gain or loss is recognized and the new lease is
accounted for as an operating lease. Under SFAS No. 145, capital leases that
are modified so the resulting lease agreement is classified as an operating
lease are to be accounted for under the sale-leaseback provisions of SFAS No.
98, Accounting for Leases.These provisions of SFAS No. 145 were effective
for transactions occurring after May 15, 2002. SFAS No. 145 will be applied as
required. Adoption of SFAS No. 145 is not expected to have a material impact
on the Company.

In June 2002, the FASB issued SFAS No. 146, Accounting for Costs
Associated with Exit or Disposal Activities,(SFAS No. 146). SFAS No. 146
addresses financial accounting and reporting for costs associated with exit or
disposal activities and nullifies EITF Issue No. 94-3, Liability Recognition
for Certain Employee Termination Benefits and Other Costs to Exit an Activity
(including Certain Costs Incurred in a Restructuring).SFAS No. 146 applies to
costs associated with an exit activity that does not involve an entity newly
acquired in a business combination or with a disposal activity covered by SFAS
No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets.The
provisions of SFAS No. 146 are effective for exit or disposal activities that
are initiated after December 31, 2002. SFAS No. 146 will be applied as
required.

In
January 2003, the FASB issued FASB Interpretation No. 46,
Consolidation
of Variable Interest Entities,(FIN No. 46). FIN No. 46 requires an enterprises
consolidated financial statements to include subsidiaries in which the
enterprise has a controlling interest. Historically, that requirement has been
applied to subsidiaries in which an enterprise has a majority voting interest,
but in many circumstances the enterprises consolidated financial statements do
not include the consolidation of variable interest entities with which it has
similar relationships but no majority voting interest. Under FIN No. 46 the
voting interest approach is not effective in identifying controlling financial
interest. The new rule requires that for entities to be consolidated that those
assets be initially recorded at their carrying amounts at the date the
requirements of the new rule first apply. If determining carrying amounts as
required is impractical, then the assets are to be measured at fair value the
first date the new rule applies. Any difference between the net amount of any
previously recognized interest in the newly consolidated entity should be
recognized as the cumulative effect of an accounting change. FIN No. 46 becomes
effective in the first interim or annual period ending after December 15, 2003.
FIN No. 46 will be applied as required and is not expected to have a material
impact on the Company.

In April 2003, the FASB issued SFAS No. 149, Amendment of Statement 133
on Derivative Instruments and Hedging Activities, (SFAS No. 149).SFAS No. 149
amends and clarifies financial accounting and reporting for derivative
instruments, including certain derivative instruments embedded in other
contracts (collectively referred to as derivatives) and for hedging activities
under FASB Statement No. 133, Accounting for Derivative Instruments and Hedging
Activities.The provisions of SFAS No. 149 are effective for contracts entered
into or modified after June 30, 2003 and for hedging relationships designated
after June 30, 2003. In addition, provisions of SFAS 149 that relate to SFAS
Statement No. 133 Implementation Issues that have been effective for fiscal
quarters that began prior to June 15, 2003, should continue to be applied in
accordance with their respective effective dates. SFAS No. 149
has not had an impact on the Company.

In May 2003, the FASB issues SFAS No. 150, Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity,
(SFAS No. 150).SFAS No. 150 establishes standards for how an issuer classifies
and measures certain financial instruments with characteristics of both
liabilities and equity. It requires that an issuer classify a financial
instrument that is

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within its scope as a liability (or an asset in some circumstances). Many
of those instruments were previously classified as equity. The provisions of
SFAS 150 are effective for financial instruments entered into or modified after
May 31, 2003, and otherwise is effective at the beginning of the first interim
period beginning after June 15, 2003. SFAS No. 150 has not had a material
impact on the Company.







Item 2.     Managements Discussion and Analysis of Financial Condition and Results of Operations

Overview

NRG
Northeast is a wholly-owned indirect subsidiary of NRG Energy. NRG
Energy is a leading independent power production company, primarily
engaged in the ownership and operation of power generation facilities and the
sale of energy, capacity and related products in the United States.
While NRG Energy is currently an indirect, wholly owned subsidiary of Xcel Energy, it
will be an independent public company upon its emergence from bankruptcy and
will no longer have any material affiliation or relationship with Xcel Energy.
NRG Energy has a diverse generation portfolio in terms of geography, fuel type
and dispatch levels. NRG Energy believes this diversity helps balance risk
and increase profits. NRG Northeast owns electric power generation
plants in the northeastern region of the United States. As part of
NRG Energys strategy, NRG Northeast intends
to maximize operating income through the efficient procurement and management
of fuel supplies, transportation and maintenance services, and the sale of
energy, capacity and ancillary services into attractive spot, intermediate and
long-term markets.

NRG
Energy and the Company do not anticipate any significant new acquisitions or
construction in the near future, and instead will focus on operational
performance, asset management and debt reduction. The Company has already made
significant reductions in capital expenditures, business development activities
and personnel. Power sales, fuel procurement and risk management will remain a
key strategic element of the Companys operations. The Companys objective
will be to optimize the operating income of its facilities within an
appropriate risk and liquidity profile.

Industry Trends.In this Managements Discussion and Analysis of
Financial Condition and Results of Operations, management discusses the
Companys historical results of operations. During 2003, the following
factors, among others, have negatively affected the Companys results of
operations:



| |  |  | Weak markets for electric energy, capacity and ancillary
services;
| | - |  | ------------------------------------------------------------------



| |  |  | a narrowing of the spark spread (the difference between power
prices and fuel costs) in most regions of the United States in which
the Companys operates power generation facilities;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | mild weather during peak seasons in regions where the Company has significant merchant capacity;
| | - |  | ------------------------------------------------------------------------------------------------



| |  |  | reduced liquidity in the energy trading markets as a result of fewer participants trading lower volumes;
| | - |  | --------------------------------------------------------------------------------------------------------



| |  |  | the imposition of price caps and other market mitigation in
markets where the Company has significant merchant capacity;
| | - |  | ------------------------------------------------------------------------------------------------------------------------



| |  |  | regulatory and market frameworks in certain markets where the
Company operates that prevents the Company from charging prices that
will enable the Company to recover its operating costs and to earn
acceptable returns on capital;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | the obligation to perform under certain long-term contracts
that are not profitable;
| | - |  | ------------------------------------------------------------------------------------



| |  |  | physical, regulatory and market constraints on transmission
facilities in certain regions that limit or prevents the Company from
selling power generated by certain of its facilities;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | limited access to capital due to the Companys financial
condition since July 2002, and the resulting contraction of the
Companys ability to conduct business in the merchant energy markets;
and
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | changes and turnover in senior and middle management since June
2002 in connection with the Companys restructuring.
| | - |  | --------------------------------------------------------------------------------------------------------------------

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The Company expects that weak market conditions will continue through 2003
and 2004, and into 2005 in some markets. Historically, the Company believed
that, as supply surpluses begin to tighten and as market rules and regulatory
conditions stabilize, prices will improve for energy, capacity and ancillary
services. This view is consistent with the Companys belief that in the long
run market prices will support an adequate rate of return on the construction
of new power generation assets needed to meet increasing demand. This view is
currently being challenged in certain markets as regulatory actions and market
rules unfold that limit the ability of merchant power companies to earn
favorable returns on existing and new investments. To the extent unfavorable
regulatory and market conditions exist in the long term, the Company could have
significant impairments of property, plant and equipment and goodwill which, in
turn, could have a material adverse effect on results of operations.

New Management.On October 21, 2003, NRG Energy announced the appointment
of David W. Crane as its new President and Chief Executive Officer, effective
December 1, 2003. Before joining NRG Energy, Mr. Crane served as the Chief
Executive Officer of London-based International Power and has over 12 years of
energy industry experience. During 2003, NRG Energy also hired several key senior and middle management
positions. Currently it is conducting a search for a new Chief Financial
Officer and anticipates the position will be filled in the months following its
emergence from bankruptcy. Upon emergence from bankruptcy, NRG Energys board
of directors will consist of Mr. Crane and ten other individuals, six of whom
will initially be designated by the members of the noteholder group serving on
the creditors committee and four of whom will initially be designated by
representatives of NRG Energys bank creditors.

Independent Public Accountants; Audit Committee. PricewaterhouseCoopers
LLP have been our independent auditors since 1995. In connection with the
appointment of a new board of directors upon our emergence from bankruptcy, we
will have an audit committee consisting of independent directors. The
committee will oversee the Companys independent auditor relationship and will
evaluate from time to time whether the Company will be best served by a change
in independent auditors. The audit committees evaluation process is intended
to ensure that we will continue to have high-quality, cost-efficient
independent auditing services.

Results of Operations

For the three months ended September 30, 2003 compared to the three months
ended September 30, 2002

Operating Revenues

Total operating revenues were $260.5 million and $233.6 million for the
three months ended September 30, 2003 and 2002, respectively, an increase of
$26.9 million or 11.5%. This increase is primarily due to increased generation
revenue. Higher natural gas prices resulted in a higher price per MW hour
generated. The effect of higher power prices was offset by lower generation.
Gas fired plants had lower generation due to the adverse price effect of
natural gas. Cooler than expected summer temperatures resulted in reduced
generation at other plants. In addition, subsequent to May 14, 2003, the
Company ceased to recognize any revenues or expenses related to the Standard
Offer Service contract with CL&P, a long-term contract with Ashland and a
long-term contract with EUA. This is due to the termination of an indemnity
agreement between the Company and NRG PMI, a wholly owned subsidiary of NRG
Energy and an affiliate of the Company. Effective May 14, 2003, NRG PMI will
bear the benefits and burdens of these contracts.

Operating Costs

Operating costs primarily consist of expenses for fuel, plant operations
and maintenance, property and other non-income related taxes and unrealized
gains or losses associated with changes in the fair value of energy related
derivative instruments not accounted for as hedges.

Operating costs were $145.4 million for the three months ended September
30, 2003 compared to $182.1 million for the three months ended September 30,
2002. This represents a decrease of $36.7 million or 20.2% for the three months
ended September 30, 2003 compared to the same periods in 2002. This decrease is
due to reduced fuel costs as a result of decreased generation, partially offset
by an increase in fuel oil and natural gas prices.

Depreciation

Depreciation expense was $14.3 million and $13.6 million for the three
months ended September 30, 2003 and 2002, respectively. In light of economic
developments related to the Connecticut assets and the FERC issued order
regarding cost of service reimbursements, the Company reassessed the asset
lives for the Connecticut facilities during 2003. The shorter depreciable
lives resulted in an increase in depreciation expense. This increase was
offset by reduced depreciable values resulting from asset impairment charges on
the Connecticut assets during the second quarter of 2003.

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General and Administrative Expenses

General and administrative expense was $12.6 million and $5.3 million for
the three months ended September 30, 2003 and 2002, respectively, an increase
of $7.3 million or 137.7%. General and administrative costs include
non-operational labor and other employee related costs, as well as outside
services, insurance, office expenses and administrative support. During the
third quarter of 2003, NRG Energy and NRG PMI began allocating certain overhead
expenses down to the project level. In addition, insurance expense increased
due to an overall increase in insurance premiums.

Restructuring and Impairment Charges

Restructuring and impairment charges were $9.6 million and $49.3 million
for the three months ended September 30, 2003 and 2002, respectively. Asset
impairment charges were $9.0 million and $49.3 million for the three months
ended September 30, 2003 and 2002, respectively. Restructuring costs were $0.5
million for the three months ended September 30, 2003. There were no
restructuring costs incurred during the three months ended September 30, 2002.

Asset impairments for the three months ended September 30, 2003 consisted
of the cancellation of a fuel oil capacity project at one of the Companys
subsidiaries.

Credit rating downgrades, defaults under certain credit agreements,
increased collateral requirements and reduced liquidity experienced by the
Company during the third quarter of 2002 were triggering events which
required NRG Northeast to review the recoverability of its long-lived assets.
Adverse economic conditions resulted in declining energy prices. As a result,
the Company determined that Somerset Power, LLC, became impaired during the
third quarter of 2002 and should be written down to fair market value. During
2002, the Company recorded impairment charges of $49.3 million.

During the three months ended September 30, 2003, the Company incurred
$0.5 million of restructuring costs consisting primarily of employee separation
costs and advisor fees.

Interest Expense

Interest expense was $14.6 million and $12.9 million for the three months
ended September 30, 2003 and 2002, respectively, an increase of $1.7 million or
13.2%. Interest expense includes amortization of deferred finance costs,
interest on the senior secured bonds issued on February 22, 2000 and an
affiliated note payable issued on June 15, 2002. After the bankruptcy filing
the Company entered into a Senior Secured, Super-Priority (Debtor-in-Possession
Credit Agreement), which costs are being amortized starting May 14, 2003.

For the nine months ended September 30, 2003 compared to the nine months ended
September 30, 2002

Operating Revenues

Total operating revenues were $603.9 million and $550.3 million for the
nine months ended September 30, 2003 and 2002, respectively, an increase of
$53.6 million or 9.7%. This increase is primarily due to increased generation
revenue. Gas fired plants had lower generation due to the adverse price effect
of natural gas. Cooler than expected summer temperatures resulted in reduced
generation at other plants. In addition subsequent to May 14, 2003, the
Company ceased to recognize any revenues or expenses related to the Standard
Offer Service contract with CL&P, a long term contract with Ashland and a long
term contract with EUA. This is due to the termination of an indemnity
agreement between the Company and NRG PMI, a wholly owned subsidiary of NRG
Energy and an affiliate of the Company. Effective May 14, 2003, NRG PMI will
bear the benefits and burdens of these contracts. Although there were
continued losses incurred on the Connecticut Standard Offer and other contract
obligations due to increased market prices, these losses were borne by NRG PMI
subsequent to May 14, 2003.

Operating Costs

Operating costs primarily consist of expenses for fuel, plant operations
and maintenance, property and other non-income related taxes and unrealized
gains or losses associated with changes in the fair value of energy related
derivative instruments not accounted for as hedges.

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Cost of operations was $500.6 million for the nine months ended September
30, 2003 compared to $390.7 million for the nine months ended September 30,
2002. This represents an increase of $109.9 million or 28.1% for the nine
months ended September 30, 2003 compared to the same period in 2002. Although
generation declined for the nine-month period ended September 30, 2003 compared
to the same period in 2002, the cost of generation increased substantially due
to increased fuel oil and natural gas prices. In addition, as a result of the
Companys financial condition, various parties exercised their rights to
terminate commodity purchase and sales contracts, which resulted in several
contract terminations during the three months ended September 30, 2003. As a
result, contract termination expense of $53.5 million was recorded. Offsetting
this expense was a favorable change in the fair value of the Companys energy
related derivatives directly resulting from the termination of these contracts.

Depreciation

Depreciation expense was $51.1 million and $39.8 million for the nine
months ended September 30, 2003 and 2002, respectively, an increase of $11.3
million or 28.4%. In light of economic developments related to the Connecticut
assets and the FERC issued order regarding cost of service reimbursements, The
Company reassessed the asset lives for the Connecticut facilities during 2003.
The shorter depreciable lives resulted in an increase in depreciation expense.
This increase was offset by reduced depreciable values resulting from asset
impairment charges on the Connecticut assets during the second quarter of 2003.

General and Administrative Expenses

General and administrative expense was $29.9 million and $16.7 million for
the nine months ended September 30, 2003 and 2002, respectively, an increase of
$13.2 million or 79.0%. During the third quarter of 2003, NRG Energy and NRG
PMI began allocating certain overhead expenses down to the project level.
Insurance expense increased due to an overall increase in insurance premiums.
In addition, the company recorded $6.2 million of bad debt expense during the
first quarter of 2003 for collectibility issues primarily related to one
contract.

Restructuring and Impairment Charges

Restructuring and impairment charges were $233.4 million and $49.3 million
for the nine months ended September 30, 2003 and 2002, respectively. Asset
impairment charges were $230.5 million and $49.3 million for the nine months
ended September 30, 2003 and 2002, respectively. Restructuring costs were $2.8
million for the nine months ended September 30, 2003. There were no
restructuring costs incurred during the nine months ended September 30, 2002.

Asset impairments for the nine-month period ended September 30, 2003
consisted of Devon Power LLC, Middletown Power LLC and a cancelled construction
project at one of the Companys subsidiaries. On
February 26, 2003, NRG Energy
filed a proposed cost-of-service agreement for the following Connecticut
facilities with the Federal Energy Regulatory Commission (FERC): Devon 11-14,
Middletown station, Montville station and Norwalk Harbor station. On April 25,
2003, the FERC issued an order that rejected NRG Energys proposed fixed
monthly charges, citing certain policy determinations regarding cost-of-service
agreements. FERC instead directed NRG Energy to recover its fixed and variable
costs under interim bidding rules for generators located in constrained areas,
the so-called Peaking Unit Safe Harbor (PUSH) mechanism. The PUSH bidding rules
would apply to all of NRG Energys Connecticut facilities that filed the
proposed cost-of-service agreements, with the exception of Middletown Units 2
and 3, until June 1, 2004. The following quick start facilities, located in
Connecticut also have submitted PUSH bids that have been approved by FERC: Cos
Cob, Franklin Drive, Branford and Torrington. FERC also ordered that the
regional power agencies overseeing the energy markets in Connecticut, the
Independent System Operator for New England (ISO-NE) and the New England Power
Pool (NEPOOL), modify the New England market rules to establish and implement
locational capacity or deliverability requirements no later than June 1, 2004.
In late May and June 2003, ISO-NE revised its market pricing rules to
facilitate FERCs mandated PUSH mechanism, but has not yet proposed the market
modifications required to implement locational capacity or deliverability
requirements. In June 2003, NRG Energy filed for rehearing of several elements
of FERCs April 25, 2003 order. In response, on July 25, 2003, FERC re-affirmed
the PUSH interim pricing mechanism.

The existing RMR between ISO-NE and NRG Energy covering Devon 7 and 8
terminated on September 30, 2003. On October 2, 2003, NRG filed to extend the
existing RMR agreements. A number of protests have been filed and FERC has yet
to act on the request to extend the agreements.

As a result of these regulatory developments and changing circumstances in
the second quarter of 2003, NRG Energy updated the facilities cash flow models
to incorporate changes to reflect the impact of the April 25, 2003 FERCs
orders on PUSH pricing, the pending termination of the RMR, and to update the
estimated impact of future locational capacity or deliverability requirements.

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Based on these revised cash flow models, management determined that the
new estimates of pricing and cost recovery levels were not projected to return
sufficient revenue to cover the fixed costs at Devon Power LLC and Middletown
Power LLC. As a consequence, during the second quarter of 2003 NRG Energy
recorded a $64.2 million and $157.3 million impairment at Devon Power LLC and
Middletown Power LLC, respectively.

During the third quarter of 2003 NRG Energy cancelled its plans to
re-establish fuel oil capacity at one of the Companys subsidiaries. This
resulted in a charge of approximately $9.0 million to write-off assets under
development.

During the nine months ended September 30, 2003, the Company incurred $1.1
million, of restructuring costs consisting of employee separation costs and
advisor fees.

Regulatory Issues

NRG Energy is impacted by market rule and tariff changes in the existing
markets operated by Independent System Operators (ISOs) and Regional
Transmission Organizations (RTOs). On March 1, 2003, ISO-New England
implemented its version of Standard Market Design. This change dramatically
modifies the New England market structure by incorporating Locational Marginal
Pricing (pricing by location rather than on a New England wide basis). While
the ISO-New England Standard Market Design represents a significant improvement
to the existing market design, NRG Energy still considered the market
insufficient to allow NRG Energy to recover its reasonable costs and earn a
reasonable return on investment. Therefore, and notwithstanding the impending
implementation of Locational Marginal Pricing, on February 26, 2003, NRG Energy
filed a proposed cost-of-service agreement with FERC for the following
Connecticut facilities: Middletown Power LLC, Montville Power LLC, Norwalk
Power LLC and Devon Power LLC units 11-14 (collectively the NRG Subsidiaries).
In the filing, NRG Energy requested that major and minor maintenance expenses
of the NRG Subsidiaries be paid for through a tracking mechanism that would
insure that NRG Energy receives compensation only for actual maintenance
expenses. Under the proposed cost-of-service agreement, the other NRG Energy
costs would be paid through a monthly cost-based payment. NRG Energy requested
an effective date of February 27, 2003.

On March 25, 2003, FERC issued an order (the March Order) approving the
recovery of the NRG Subsidiaries Spring 2003 maintenance expenses, subject to
refund and authorized an effective date of February 27, 2003. FERC did not rule
on the remainder of the issues allowing further time to consider protests.

On April 25, 2003, the FERC issued an order (the April Order) rejecting
the remaining part of the proposed cost-of-service agreements including the
monthly cost-based payment. Rather, FERC instructed ISO New England to
establish temporary bidding rules that would permit selected peaking units
(units with capacity factors of 10 percent or less during 2002), operating
within designated congestion areas (such as Connecticut) to raise their bids
to allow them the opportunity to recover their fixed and variable costs through
the market. This temporary bidding rule would remain in place until ISO New
England implements locational installed capacity requirements, which should be
no later than June 1, 2004. In the July 24 Order on Rehearing (the July Order),
FERC clarified that the capacity factor of 10 percent or less applies to units
rather than complexes. On a unit basis, all the NRG Energy facilities qualify
to bid under the temporary rules except Middletown 2 and 3, and Devon 7 and 8.
The RMR agreement between ISO New England and NRG Energy covering Devon 7 and 8
terminated on September 30, 2003. On October 2, 2003, NRG Energy filed the
existing RMR agreement. FERC has yet to act on the request to extend the
agreement.

On October 17, 2003, the Midwest Independent Transmission Operator, Inc.
(MISO) filed a motion to withdraw its Open Access Transmission and Energy
Markets Tariff (TEMT), purportedly to allow more time to develop stakeholder
consensus on critical outstanding issues relating to market features such as
Fixed Transmission Rights, market monitoring and resource adequacy.
Post-blackout reliability concerns were also a stated factor for the
withdrawal. On October 29, 2003, FERC granted the MISOs motion. The MISO had
planned to phase-in its energy markets during 2004. The withdrawal of the
market tariff means that the market will be delayed for an undetermined period
of time.

Interest Expense

Interest expense was $40.3 million and $39.6 million for the nine months
ended September 30, 2003 and 2002, respectively, an increase of $0.7 million or
1.8%. This increase is due to the additional interest costs related to the
affiliated note payable and

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amortization of deferred finance costs related to the Debtor-in Possession
Agreement.

Accounting Policies and Estimates

Managements discussion and analysis of its financial condition and
results of operations are based upon the Companys consolidated financial
statements, which have been prepared in accordance with accounting principles
generally accepted in the United States of America. The preparation of these
financial statements and related disclosures in compliance with generally
accepted accounting principles requires the application of appropriate
technical accounting rules and guidance as well as the use of estimates and
judgments that affect the reported amounts of assets, liabilities, revenues and
expenses. These judgments, in and of themselves, could materially impact the
financial statements and disclosures based on varying assumptions, which may be
appropriate to use. In addition, the financial and operating environment also
may have a significant effect, not only on the operation of the business, but
on the results reported through the application of accounting measures used in
preparing the financial statements and related disclosures, even if the nature
of the accounting policies have not changed.

On an ongoing basis, the Company evaluates its estimates utilizing
historic experience, consultation with experts and other methods the Company
considers reasonable. In any case, actual results may differ significantly from
the Companys estimates. Any effects on the Companys business, financial
position or results of operations resulting from revisions to these estimates
are recorded in the period in which the facts that give rise to the revision
become known.

Refer to Item 15 Note 2 of the consolidated financial statements of the
Companys Form 10-K for the year ended December 31, 2002 for additional
discussion regarding the Companys accounting policies and estimates.

Liquidity and Capital Resources

Liquidity Issues of NRG Energy and it Subsidiaries  Current Status and
Chain of Events

During 2002, Xcel Energy contributed $500 million to NRG Energy, and NRG
Energy and its subsidiaries sold assets and businesses that provided NRG Energy
in excess of $286 million in cash and eliminated approximately $432 million in
debt. NRG Energy also cancelled or deferred construction of approximately 3,900
MW of new generation projects. On July 26, 2002, Standard & Poors (S&P)
downgraded NRG Energys senior unsecured bonds to below investment grade, and
three days later Moodys also downgraded NRG Energys senior unsecured debt
rating to below investment grade. Currently, NRG Energys unsecured bonds carry
a rating of D at S&P and Ca at Moodys.

In August 2002, NRG Energy retained financial and legal restructuring
advisors to assist its management in the preparation of a comprehensive
financial and operational restructuring. In November 2002, NRG Energy and Xcel
Energy presented a comprehensive plan of restructuring to an ad hoc committee
of its bondholders and a steering committee of its bank lenders (the Ad Hoc
Creditors Committees). The restructuring plan served as a basis for continuing
negotiations between the Ad Hoc Creditors Committees, NRG Energy and Xcel
Energy related to a consensual plan of reorganization for NRG Energy.

On March 26, 2003, Xcel Energy announced that its board of directors had
approved a tentative settlement agreement with holders of most of NRG Energys
long-term notes and the steering committee representing NRG Energys bank
lenders. The terms of the settlement call for Xcel Energy to make payments to
NRG Energy totaling up to $752 million for the benefit of NRG Energys
creditors in consideration for their waiver of any existing and potential
claims against Xcel Energy. Under the settlement, Xcel Energy would make the
following payments: (i) $350 million, up to $150 million of which may be in
Xcel Energy common stock if Xcel Energys public debt fails to maintain a
certain rating, on the later of: (a) 90 days after NRG Energys plan of
reorganization is confirmed by the Bankruptcy Court, and (b) one day after the
effective date of NRG Energys plan of reorganization; (ii) $50 million in the
first quarter of 2004. At Xcel Energys option, it may fill this requirement
with either cash or Xcel Energy common stock or any combination thereof; and
(iii) up to $352 million in April 2004. Since the announcement on March 26,
2003, representatives of NRG Energy, Xcel Energy, the bank lenders and
noteholders continued to meet to draft the definitive documentation necessary
to fully implement the terms and conditions of the tentative settlement
agreement. The final settlement agreement between Xcel Energy and NRG Energy
is subject to the Bankruptcy Court approval including certain provisions and conditions
in its order approving the confirmation of NRG Energys plan of reorganization
and the satisfaction, or waiver by Xcel Energy, of certain other conditions (including
obtaining requisite releases of Xcel Energy by NRG Energy creditors). There can be no
assurance that such conditions will be met.

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As noted above, on May 14, 2003, the Debtors filed the Chapter 11 Cases.
NRG Energy expects operations to continue as normal during the restructuring
process, while it operates its business as a debtor-in-possession under the
jurisdiction of the Bankruptcy Court and in accordance with the applicable
provisions of the Bankruptcy Code and orders of the Bankruptcy Court. In
connection with its Chapter 11 filing, NRG Energy also announced that it had
secured a $250 million debtor-in-possession (DIP) financing facility from GE
Capital Corporation, subject to Bankruptcy Court approval, to be utilized by
its NRG Northeast Generating LLC subsidiary ( NRG Northeast) and some NRG
Northeast subsidiaries. The Bankruptcy Court entered an order approving the DIP
facility on July 24, 2003. NRG Energy anticipates that the DIP, together with
its cash reserves and its ongoing revenue stream, will be sufficient to fund
its operations, including payment of employee wages and benefits, during the
negotiation process.

Subsequent to the Petition Date, additional NRG Energy subsidiaries filed
petitions for reorganization with the Bankruptcy Court. On June 5, 2003 NRG
Nelson Turbines LLC and LSP-Nelson Energy LLC (both wholly owned subsidiaries
of NRG Energy) filed voluntary petitions for reorganization under Chapter 11 of
the Bankruptcy Code in the Bankruptcy Court. On August 19, 2003, NRG McClain
LLC (a wholly owned subsidiary of NRG Energy) filed a voluntary petition for
reorganization under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court.

On May 15, 2003, NRG Energy announced that it had been notified that the
New York Stock Exchange (NYSE) has suspended trading in NRG Energys corporate
units that trade under the ticker symbol NRZ (Units) and that an application to
the Securities and Exchange Commission to delist the Units is pending the
completion of applicable procedures, including appeal by NRG Energy of the NYSE
staffs decision. NRG Energy does not plan to make such an appeal. The NYSE
took this action following NRG Energys announcement that it and certain of its
affiliates had filed voluntary positions for reorganization under Chapter
11 of the U.S. Bankruptcy Code.

In addition, on May 15, 2003, NRG Energy, NRG Power Marketing, Inc. (NRG PMI),
NRG Finance Company I LLC, NRGenerating Holdings (No. 23) B.V. and NRG Capital
LLC (collectively, the Plan Debtors) filed their Disclosure Statement for
Reorganizing Debtors Joint Plan of Reorganization Pursuant to Chapter 11 of
the United States Bankruptcy Code (as subsequently amended, the Disclosure
Statement). The Bankruptcy Court held a hearing on the Disclosure Statement on
June 30, 2003, and instructed the Plan Debtors to include certain additional
disclosure. The Plan Debtors amended the Disclosure Statement and obtained
Bankruptcy Court approval for the Third Amended Disclosure Statement for
Debtors Second Amended Joint Plan of Reorganization Pursuant to Chapter 11 of
the Bankruptcy Code (respectively, the Amended Disclosure Statement, the Plan)
on October 14, 2003.

The Plan must be approved by the SEC prior to its becoming effective. As
subsidiaries of a registered holding company (Xcel Energy) under the Public
Utility Holding Company Act of 1935 (PUHCA), any reorganization plan for NRG
Energy or NRG Energys subsidiaries must be approved by the SEC prior to such
plan becoming effective. Furthermore, each solicitation of any consent in
respect of any reorganization plan must be accompanied or preceded by a copy of
a report on the plan made by the SEC, or an abstract thereof made or approved
by the SEC. The Plan and Amended Disclosure Statement were submitted to the SEC
for review on July 28, 2003. The SEC issued an order approving the Plan
on October 10, 2003, permitting the Plan Debtors, subject to the approval of
the Bankruptcy Court, to commence solicitation of votes on the Plan.

The Plan Debtors commenced solicitation of votes on the Plan on October
14, 2003. The voting deadline by which holders of claims and equity interests
of the Plan Debtors must submit their ballots accepting or rejecting the Plan
is November 12, 2003. Objections to confirmation of the Plan must be filed
with Bankruptcy Court by November 12, 2003. The Bankruptcy Court has scheduled
the confirmation hearing to determine whether the Plan should be confirmed on
November 21, 2003.

If the Plan is confirmed, holders of NRG Energy unsecured claims
(including bank and bond debt) will receive a combination of New NRG Energy
common stock, New NRG Energy senior notes and cash for an estimated percentage
recovery of 50.7%. Holders of NRG PMI unsecured claims will receive a combination
of New NRG Energy common stock and New NRG Energy senior notes
for an estimated percentage recovery of 44.6%. If the Plan is confirmed,
certain other holders of claims or equity interests in the Plan Debtors will
(i) have their claims paid in full in accordance with the Bankruptcy Code,
(ii) have their claims or equity interests reinstated, or (iii) have their
claims or equity interests cancelled, and receive no distribution on account of
such claims or equity interests. Upon emergence from bankruptcy, Xcel Energys
ownership interest in NRG Energy will be cancelled and ownership in NRG Energy
will vest in the unsecured creditors of NRG Energy and NRG PMI.

On September 17, 2003, NRG Northeast and NRG South Central Generating LLC
(NRG South Central) and certain of their subsidiaries and affiliates filed a
plan of reorganization with the Bankruptcy Court (the NRG Northeast and NRG
South Central Plan). The debtors under the NRG Northeast and NRG South Central
Plan are not soliciting votes for approval of the NRG Northeast and NRG South Central Plan

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because none of the holders of claims or equity
interests are impaired under the NRG Northeast and NRG South Central Plan. The
Bankruptcy Court has scheduled a hearing on the confirmation of the NRG
Northeast and NRG South Central Plan on November 21, 24 and 25, 2003.

During the Chapter 11 Cases, the Debtors may, subject to any necessary
Bankruptcy Court and lender approvals, sell assets and settle liabilities for
amounts other than those reflected in the financial statements. The
administrative and reorganization expenses resulting from Chapter 11 Cases will
unfavorably affect the Debtors results of operations. Future results of
operations may also be adversely affected by other factors related to Chapter
11 Cases.

The Company is in the process of reconciling recorded prepetition
liabilities with claims filed by creditors with the Bankruptcy Court.
Differences resulting from that reconciliation process will be recorded as
adjustments to prepetition liabilities. The Company recently began this
process and has not yet determined the reorganization adjustments.

Cash Flows

For the nine months endedSeptember 30,(In thousands)
    
    2003
    
    2002Net cash provided by operating activities
    
    $
    446
    
    
    $
    45,546


Net cash provided by operating activities for the nine months ended
September 30, 2003 decreased compared to the same period in 2002. This
decrease is primarily due to unfavorable operating results. The decrease due
to operating results was offset by improved working capital resulting from
reduced accounts receivable balances.

For the nine months endedSeptember 30,(In thousands)
    
    2003
    
    2002Net cash used by investing activities
    
    $
    (7,137
    )
    
    $
    (22,098
    )


Net cash used by investing activities for the nine months ended September
30, 2003, was favorably impacted as compared to the same period in 2002 due to
a reduction in capital expenditures and further enhanced by cash proceeds
received upon sale of property during 2003.

For the nine months endedSeptember 30,(In thousands)
    
    2003
    
    2002Net cash used by financing activities
    
    $
    (7,537
    )
    
    $
    (23,500
    )


Net cash used by financing activities for the nine months ended September
30, 2003 was favorably impacted as compared to the same period in 2002 due to
debt principal payments not being made during 2003, offset in part by no
borrowings during 2003 and additional deferred financing costs in connection
with the DIP financing arrangements.

Off Balance-Sheet Arrangements

As of September 30, 2003, the Company does not have any significant
relationships with structured finance or special purpose entities that provide
liquidity, financing or incremental market risk or credit risk.

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Contractual Obligations and
Commercial Commitments

The Company has a variety of contractual obligations and other commercial
commitments that represent prospective cash requirements in addition to its
capital expenditure program. The following is a summarized table of contractual
obligations. See additional discussion in Item 15 and Notes 6, 7 and 12 to the
Consolidated Financial Statements of the Companys Form 10-K filing for the
year ended December 31, 2002.

Payments Due by Period Subsequent to September 30, 2003Total
    
    Short Term
    
    1-3 Years
    
    4-5 Years
    
    After 5 Years(In thousands)Long term debt
    
    $
    556,500
    
    
    $
    556,500
    
    
    $
    
    
    
    $
    
    
    
    $
    Operating leases
    
    
    6,676
    
    
    
    780
    
    
    
    1,536
    
    
    
    1,048
    
    
    
    3,312Note payable  affiliate
    
    $
    30,000
    
    
    $
    30,000
    
    
    
    
    
    
    
    
    
    
    
    Total contractual cash
obligations
    
    $
    593,176
    
    
    $
    587,280
    
    
    $
    1,536
    
    
    $
    1,048
    
    
    $
    3,312


Amount of Commitment by Expiration Period as of September 30, 2003Total AmountsCommitted
    
    Short Term
    
    1-3 Years
    
    4-5 Years
    
    After 5 Years(In thousands)Guarantees
    
    $
    35,300
    
    
    $
    17,000
    
    
    $
    5,000
    
    
    $
    
    
    
    $
    13,300Total guarantees
    
    $
    35,300
    
    
    $
    17,000
    
    
    $
    5,000
    
    
    $
    
    
    
    $
    13,300


The Company provides performance guarantees to third parties on behalf of
NRG Power Marketing in relation to certain of its sales and supply agreements.

Derivative Instruments

The tables below disclose the Companys derivative activities that include
non-exchange traded contracts accounted for at fair value. Specifically, these
tables disaggregate realized and unrealized changes in fair value; identify
changes in fair value attributable to changes in valuation techniques;
disaggregate estimated fair values at the three and nine months ended September
30, 2003 based on whether fair values are determined by quoted market prices or
more subjective means; and indicate the maturities of contracts at the three
and nine months ended September 30, 2003.

Derivative Activity

Three Months Ended
    
    Nine Months EndedGains/(Losses)(In thousands)
    
    September 30, 2003
    
    September 30, 2003Fair value of contracts outstanding at the beginning of the period
    
    $
    2,938
    
    
    $
    (3,641
    )Contracts realized or otherwise settled during the period
    
    
    6,813
    
    
    
    41,209Fair value of new contract when entered into during the period
    
    
    
    
    
    
    Changes in fair values attributable to changes in valuation
techniques
    
    
    
    
    
    
    Other changes in fair values
    
    
    (10,144
    )
    
    
    (37,961
    )Fair value of contracts outstanding at the end of the period
    
    $
    (393
    )
    
    $
    (393
    )


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Sources of Fair Value Gains/(Losses)

Fair Value of Contracts at Period EndMaturity
    
    
    
    
    
    
    
    
    
    Maturity inLess than 1
    
    Maturity
    
    Maturity
    
    excess of
    
    Total FairMaturity schedule (In thousands)........
    
    Year
    
    1-3 Years
    
    4-5 Years
    
    5 Years
    
    ValuePrices actively quoted
    
    $
    (393
    )
    
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    
    
    
    $
    
    
    
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    
    
    
    $
    (393
    )Prices provided by other external sources
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Prices based on models & other valuation
methods
    
    
    
    
    
    
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    
    
    
    
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    $
    (393
    )
    
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    (393
    )


Recent Accounting Pronouncements

In April 2002, the FASB issued SFAS No. 145, Rescission of FASB
Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections,that supersedes previous guidance for the reporting of gains and
losses from extinguishment of debt and accounting for leases, among other
things. SFAS No. 145 requires that only gains and losses from the
extinguishment of debt that meet the requirements for classification as
Extraordinary Items, as prescribed in Accounting Practices Board Opinion No.
30, should be disclosed as such in the financial statements. Previous guidance
required all gains and losses from the extinguishment of debt to be classified
as Extraordinary Items. This portion of SFAS No. 145 is effective for fiscal
years beginning after May 15, 2002, with restatement of prior periods required.
The Company adopted this standard as of January 1, 2003 and has no
extraordinary gains or losses that will require restatement.

In addition, SFAS No. 145 amends SFAS No. 13, Accounting for Leases,as
it relates to accounting by a lessee for certain lease modifications. Under
SFAS No. 13, if a capital lease is modified in such a way that the change gives
rise to a new agreement classified as an operating lease, the assets and
obligation are removed, a gain or loss is recognized and the new lease is
accounted for as an operating lease. Under SFAS No. 145, capital leases that
are modified so the resulting lease agreement is classified as an operating
lease are to be accounted for under the sale-leaseback provisions of SFAS No.
98, Accounting for Leases.These provisions of SFAS No. 145 were effective
for transactions occurring after May 15, 2002. SFAS No. 145 will be applied as
required. Adoption of SFAS No. 145 is not expected to have a material impact
on the Company.

In June 2002, the FASB issued SFAS No. 146, Accounting for Costs
Associated with Exit or Disposal Activities,(SFAS No. 146). SFAS No. 146
addresses financial accounting and reporting for costs associated with exit or
disposal activities and nullifies EITF Issue No. 94-3, Liability Recognition
for Certain Employee Termination Benefits and Other Costs to Exit an Activity
(including Certain Costs Incurred in a Restructuring).SFAS No. 146 applies to
costs associated with an exit activity that does not involve an entity newly
acquired in a business combination or with a disposal activity covered by SFAS
No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets.The
provisions of SFAS No. 146 are effective for exit or disposal activities that
are initiated after December 31, 2002. SFAS No. 146 will be applied as
required.

In
January 2003, the FASB issued FASB Interpretation No. 46,
Consolidation
of Variable Interest Entities,(FIN No. 46). FIN No. 46 requires an enterprises
consolidated financial statements to include subsidiaries in which the
enterprise has a controlling interest. Historically, that requirement has been
applied to subsidiaries in which an enterprise has a majority voting interest,
but in many circumstances the enterprises consolidated financial statements do
not include the consolidation of variable interest entities with which it has
similar relationships, but no majority voting interest. Under FIN No. 46 the
voting interest approach is not effective in identifying controlling financial
interest. The new rule requires that for entities to be consolidated that those
assets be initially recorded at their carrying amounts at the date the
requirements of the new rule first apply. If determining carrying amounts as
required is impractical, then the assets are to be measured at fair value as of
the first date the new rule applies. Any difference between the net amounts of
any previously recognized interest in the newly consolidated entity should be
recognized as the cumulative effect of an accounting change. FIN No. 46 becomes
effective in the first interim or annual period ending after December 15, 2003.
FIN No. 46 will be applied as required and is not expected to have a material
impact on the Company.

In April 2003, the FASB issued SFAS No. 149, Amendment of Statement 133
on Derivative Instruments and Hedging Activities, (SFAS No. 149).SFAS No. 149
amends and clarifies financial accounting and reporting for derivative
instruments, including certain derivative instruments embedded in other
contracts (collectively referred to as derivatives) and for hedging activities
under FASB Statement No. 133, Accounting for Derivative Instruments and Hedging
Activities.The provisions of SFAS No. 149 are effective for contracts entered
into or modified after June 30, 2003 and for hedging relationships designated
after June 30, 2003. In addition,

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provisions of SFAS 149 relating to SFAS Statement No. 133 Implementation
Issues and effective for fiscal quarters beginning prior to June 15, 2003,
should continue to be applied in accordance with their respective effective
dates. SFAS No. 149 has not had an impact on the Company.

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity,
(SFAS No. 150).SFAS No. 150 establishes standards for how an issuer classifies
and measures certain financial instruments with characteristics of both
liabilities and equity. It requires that an issuer classify a financial
instrument that is within its scope as a liability (or an asset in some
circumstances). Many of those instruments were previously classified as equity.
The provisions of SFAS No. 150 are effective for financial instruments entered
into or modified after May 31, 2003, and otherwise are effective at the
beginning of the first interim period beginning after June 15, 2003.
SFAS No. 150 has not had a material impact on the Company.







Item 3.     Quantitative and Qualitative Disclosures About Market Risk

The Company is exposed to market risks, including changes in commodity
prices and interest rates, and credit risk as disclosed in Managements
Discussion and Analysis in its annual report on Form 10-K for the year ended
December 31, 2002. Except as follows, there have been no material changes as of
September 30, 2003 to the market risk disclosures presented as of December 31,
2002.

Commodity Price Risk

The Company is exposed to commodity price variability in electricity,
emission allowances and natural gas, oil and coal used to meet fuel
requirements. To manage earnings volatility associated with these commodity
price risks, the Company, through its affiliate NRG Power Marketing, may enter
into financial instruments, which may take the form of fixed price, floating
price or indexed sales or purchases, and options, such as puts, calls, basis
transactions and swaps.

Through NRG Power Marketing, the Company utilizes an undiversified
Value-at-Risk (VAR) model to determine the maximum potential three-day loss
in the fair value of the commodity price related financial instruments for the
forward twelve months. The VAR for the Company assumes a 95% confidence
interval and reflects the Companys merchant strategy, the generation assets,
load obligations and the bilateral physical and financial transactions of the
Company. The volatility estimate is based on the implied volatility for at the
money daily call options for forward markets where the Company has exposure.
This model encompasses the ISO-NE and NYISO generating regions.

The estimated maximum potential three-day loss in fair value of the
commodity price related financial instruments, calculated using the VAR model,
is approximately $94.0 million and $66.4 million as of September 30, 2003 and
2002, respectively. The average, high and low amounts for the nine months ended
September 30, 2003 were $114.4 million, $137.9 million and $94.0 million,
respectively. The average, high and low amounts for the nine months ended
September 30, 2002 were $53.5 million, $67.5 million and $46.6 million,
respectively.







Item 4. Controls and Procedures

The Chairman, Senior Vice President, General Counsel, Vice President and
Treasurer and Vice President and Controller (the Certifying Officers) have
evaluated NRG Energys disclosure controls and procedures as defined in the
rules of the SEC as of the end of the period covered by this report and have
determined that, except to the extent indicated otherwise in this paragraph,
disclosure controls and procedures were effective in ensuring that material
information required to be disclosed by NRG Energy in the reports filed under
the Securities Exchange Act of 1934 is recorded, processed, summarized and
reported within the time periods specified in the SECs rules and forms. During
the fourth quarter of 2002, the Certifying Officers determined that there were
certain deficiencies in the internal controls relating to financial reporting
at NRG Energy caused by NRG Energys pending financial restructuring and
business realignment. During the second half of 2002, there were material
changes and vacancies in senior NRG Energy management positions and a diversion
of NRG Energy financial and management resources to restructuring efforts.
These circumstances detracted from NRG Energys ability through its internal
controls to timely monitor and accurately assess the impact of certain
transactions, as would be expected in an effective financial reporting control
environment. During 2003 NRG Energy has dedicated significant resources to make
corrections to those control deficiencies, including hiring several key senior
and middle management positions, hiring an outside consultant to review,
document and suggest improvements to controls, and the implementation of new
controls and procedures. NRG Energy will continue to dedicate resources to
this effort over the next few months. In addition, on October 21, 2003, NRG
Energy announced the appointment of David W. Crane as its new President and
Chief Executive Officer, effective December 1, 2003. NRG Energy is currently
conducting a search for a new Chief Financial Officer and anticipates the
position will be filled in the months following its emergence from bankruptcy.
Notwithstanding the foregoing and as indicated in the certification
accompanying the signature page to this report, the Certifying Officers have
certified that, to the best of their knowledge, the financial statements, and
other financial information included in this report on Form 10-Q, fairly
present in all material respects the financial conditions, results of
operations and cash flows of NRG Energy as of, and for the periods presented in
this report.

NRG Energys Certifying Officers are primarily responsible for the
accuracy of the financial information that is represented in this report. To
meet their responsibility for financial reporting, they have established
internal controls and procedures, which, subject to the disclosure in the
foregoing paragraph, they believe, are adequate to provide reasonable assurance
that NRG Energy assets are protected from loss. There were no significant
changes in internal controls or in other factors that could significantly
affect these controls subsequent to the date of the Certifying Officers
evaluation.

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Part II  OTHER INFORMATION

Item 1. Legal Proceedings

For a discussion of material legal proceedings in which the Company was
involved through September 30, 2003, see Note 8, Commitments and
Contingencies to NRG Northeasts Consolidated Financial Statements and
Footnotes contained in Part I, Item 1 of this Form 10-Q.







Item 3.     Defaults Upon Senior Securities

The Company has identified the following material defaults with respect to
the indebtedness of the Company and its significant subsidiaries:

$320 million of 8.065% Series A Senior Secured Bonds due 2004 issued by
NRG Northeast Generating LLC



| |  |  | Failure to make $53.5 million principal payment on December 15,
2002
| | - |  | --------------------------------------------------------------------



| |  |  | Failure to make $17.5 million principal payment on June 15, 2003
| | - |  | ----------------------------------------------------------------



| |  |  | Failure to fund debt service reserve account
| | - |  | --------------------------------------------

$130 million of 8.824% Series B Senior Secured Bonds due 2015 issued by
NRG Northeast Generating LLC



| |  |  | Failure to fund debt service reserve account
| | - |  | --------------------------------------------

$300 million of 9.29% Series C Senior Secured Bonds due 2024 issued by NRG
Northeast Generating LLC



| |  |  | Failure to fund debt service reserve account
| | - |  | --------------------------------------------

In addition to the foregoing, there may be additional technical defaults
with respect to these or other NRG Northeast debt instruments. Defaults on or
acceleration of the foregoing debt instruments may result in cross-defaults on
or cross-acceleration of these or other NRG Northeast debt instruments.
However, the Company made a total of $24.8 million of interest payments due
June 15, 2003 on the Series A, B and C Bonds.







Item 6.     Exhibits and Reports on Form 8-K

(a) Exhibits

31
    
    Section 302 Certifications32
    
    Section 906 Certification


(b) Reports on Form 8-K:None







Cautionary Statement Regarding Forward-Looking Statements

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The information presented in this quarterly report includes
forward-looking statements in addition to historical information. These
statements involve known and unknown risks and relate to future events, or
projected business results. In some cases forward-looking statements may be
identified by their use of such words as may, expects, plans,
anticipates, contemplates, believes, and similar terms. Forward-looking
statements are only predictions or expectations and actual results may differ
materially from the expectations expressed in any forward-looking statement.
While the Company believes that the expectations expressed in such
forward-looking statements are reasonable, the Company can give no assurances
that these expectations will prove to have been correct. In addition to any
assumptions and other factors referred to specifically in connection with such
forward-looking statements, factors that could cause actual results to differ
materially from those contemplated in any forward-looking statements include,
among others, the following:



| |  |  | NRG Energys ability to borrow additional funds and access capital
markets;
| | - |  | ---------------------------------------------------------------------------



| |  |  | NRG Energys substantial indebtedness and the possibility that NRG
Energy may incur additional indebtedness going forward;
| | - |  | --------------------------------------------------------------------------------------------------------------------------



| |  |  | Restrictions on the ability to pay dividends, make distributions or
otherwise transfer funds to NRG Energy contained in the debt agreements
of certain of NRG Energys subsidiaries and project affiliates
generally;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Volatility of energy and fuel prices and the possibility that NRG
Energy will not have sufficient working capital and collateral to post
performance guarantees or margin calls to mitigate such risks or manage
such volatility;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Reduced competition in the power generation industry as regulators in
certain markets advocate and allow utilities and utility holding
companies to transfer unprofitable generation assets from non-utility
entities to regulated utility entities (where costs can be recovered
through regulated cost-of-serve rates);
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Certain of NRG Energys pre-petition creditors may receive NRG Energy
common stock upon NRG Energys emergence from bankruptcy and will have
the right to select NRG Energys board members and influence certain
aspects of NRG Energys business operations;
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | The condition of the capital markets generally, which will be
effected by interest rates, foreign currency fluctuations and general
economic conditions;
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Changes in the wholesale power market, including reduced liquidity
which may limit opportunities to capitalize on short-term price
volatility;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Trade, monetary, fiscal, taxation, and environmental policies of
governments, agencies and similar organizations in geographic areas
where The Company has a financial interest;
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Changes in government regulation, including but not limited to
pending changes of market rules, market structures, rates, tariffs,
environmental regulations, and regulatory compliance requirements
imposed by the Federal Energy Regulatory Commission (FERC), state
commissions, other state regulatory agencies, the Environmental
Protection Agency (EPA), the National Electric Reliability Council
(NERC) or other regulatory or industry bodies;
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Cost and other effects of legal and administrative proceedings,
settlements, investigations and claims, including claims which are not
discharged in the bankruptcy proceedings and claims arising after the
date of the Companys bankruptcy filing;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | The impact of the bankruptcy proceedings on NRG Energys or the
Companys operations going forward, including the impact on NRG Energys
ability to negotiate favorable terms with suppliers, customers,
landlords and others.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Financial or regulatory accounting principles or policies imposed by
the Financial Accounting Standards Board, or FASB, the SEC, the FERC
and similar entities with regulatory oversight;
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Factors affecting power generation operations such as unusual weather
conditions; catastrophic weather-related or other damage to facilities;
unscheduled generation outages, maintenance or repairs; unanticipated
changes to fossil fuel, or gas supply costs or availability due to
higher demand, shortages, transportation problems or other developments;
environmental incidents; or electric transmission or gas pipeline system
constraints;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Large energy blackouts, such as the blackout that impacted parts of
the northeastern United States and Canada during the middle of August
2003, which have the potential to reduce NRG Energys revenue
collection, increase NRG Energys costs and engender enhanced federal
and state regulatory requirements;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

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| |  |  | The Companys inability to enter into intermediate and long-term
contracts to sell power and procure fuel on terms and prices acceptable
to the Company;
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Failure of customers and suppliers to perform under agreements,
including failure to deliver procured commodities and services and
failure to remit payment as required and directed, especially in
instances where the Company is relying on single suppliers or single
customers at a particular facility;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Employee workforce factors including the hiring and retention of key
executives, including NRG Energys new CEO, collective bargaining
agreements with union employees, or work stoppages;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Factors associated with various investments including partnership
actions, competition, operating risks, dependence on certain suppliers
and customers and domestic and foreign environmental and energy
regulations;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Limitations on the Companys ability to control projects in which the Company has less than 100% interest;
| | - |  | ----------------------------------------------------------------------------------------------------------



| |  |  | Uncertainties affecting the financial projections prepared in connection with the bankruptcy;
| | - |  | ---------------------------------------------------------------------------------------------



| |  |  | Risks associated with timely completion of capital improvement and
re-powering projects, including supply interruptions, work stoppages,
labor disputes, social unrest, weather interferences, unforeseen
engineering, environmental or geological problems and unanticipated cost
overruns;
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Failure to sell certain assets in the amounts and on the timetable
assumed, including failure to timely satisfy the closing conditions
contained in the definitive agreements for the sale of projects but not
yet closed, many of which are beyond NRG Energys control;
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Effects of political, regulatory and legal conditions on our international operations;
| | - |  | --------------------------------------------------------------------------------------



| |  |  | Acts of terrorism both in the United States and internationally; and
| | - |  | --------------------------------------------------------------------



| |  |  | Other business or investment considerations that may be disclosed
from time to time in our SEC filings or in other publicly disseminated
written documents.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------

The Company undertakes no obligation to update or revise any
forward-looking statements, whether as a result of new information, future
events or otherwise. The foregoing review of factors that could cause the
Companys actual results to differ materially from those contemplated in any
forward-looking statements included in this Form 10-Q should not be construed
as exhaustive.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.

NRG Northeast Generating LLC
(Registrant)/s/ Scott J. Davido

Scott J. Davido,
Vice President
(Principal Executive Officer)/s/ George P. Schaefer

George P. Schaefer, Treasurer
(Principal Financial Officer)/s/ William T. Pieper

William T. Pieper, Controller
(Principal Accounting Officer)


Date: November 13, 2003

35